CHAPTER 43-02-03

OIL AND GAS CONSERVATION

Section

43-02-03-01 Denitions

43-02-03-02 Scope of Chapter

43-02-03-03 Promulgation of Rules, Regulations, or Orders [Repealed]

43-02-03-04 Emergency Rule, Regulation, or Order [Repealed]

43-02-03-05 Enforcement of Laws, Rules, and Regulations Dealing With

Conservation of Oil and Gas

43-02-03-06 Waste Prohibited

43-02-03-07 United States Government Leases

43-02-03-08 Classifying and Dening Pools [Repealed]

43-02-03-09 Forms Upon Request

43-02-03-10 Authority to Cooperate With Other Agencies

43-02-03-11 Organization Reports

43-02-03-12 Reservoir Surveys

43-02-03-13 Record of Wells

43-02-03-14 Access to Records

43-02-03-14.1 Verication of Certied Welders [Repealed]

43-02-03-14.2 Oil and Gas Metering Systems

43-02-03-15 Bond and Transfer of Wells

43-02-03-16 Application for Permit to Drill and Recomplete

43-02-03-16.1 Designation and Responsibilities of Operator

43-02-03-16.2 Revocation and Limitation of Drilling Permits

43-02-03-16.3 Recovery of a Risk Penalty

43-02-03-17 Sign on Well

43-02-03-18 Drilling Units - Well Locations

43-02-03-18.1 Exception Location

43-02-03-19 Site Construction

43-02-03-19.1 Fencing, Screening, and Netting of Drilling and Reserve Pits

43-02-03-19.2 Disposal of Waste Material

43-02-03-19.3 Earthen Pits and Open Receptacles

43-02-03-19.4 Drilling Pits

43-02-03-19.5 Reserved Pit for Drilling Mud and Drill Cuttings From Shallow

Wells

43-02-03-20 Sealing Off Strata

43-02-03-21 Casing, Tubing, and Cementing Requirements

43-02-03-22 Defective Casing or Cementing

43-02-03-23 Blowout Prevention

43-02-03-24 Pulling String of Casing

43-02-03-25 Deviation Tests and Directional Surveys

43-02-03-26 Multiple Zone Completions

43-02-03-27 Perforating, Fracturing, and Chemically Treating Wells

43-02-03-27.1 Hydraulic Fracture Stimulation

43-02-03-28 Safety Regulation

43-02-03-29 Well and Lease Equipment

43-02-03-30 Notication of Fires, Leaks, Spills, or Blowouts

43-02-03-30.1 Leak and Spill Cleanup

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43-02-03-31 Well Log, Completion, and Workover Reports

43-02-03-32 Stratigraphic Test or Core Holes

43-02-03-33 Notice of Intention to Plug Well

43-02-03-34 Method of Plugging

43-02-03-34.1 Reclamation of Surface

43-02-03-35 Conversion of Mineral Wells to Freshwater Wells

43-02-03-36 Liability

43-02-03-37 Slush Pits [Repealed]

43-02-03-38 Preservation of Cores and Samples [Repealed]

43-02-03-38.1 Preservation of Cores and Samples

43-02-03-39 Limiting Gas-Oil Ratio

43-02-03-39.1 Oil Production Limitation

43-02-03-40 Gas-Oil Ratio Test

43-02-03-41 Subsurface Pressure Tests

43-02-03-42 Commingling of Oil From Pools

43-02-03-43 Control of Multiply Completed Wells [Repealed]

43-02-03-44 Metered Casinghead Gas

43-02-03-45 Vented Casinghead Gas

43-02-03-46 Use of Vacuum Pumps [Repealed]

43-02-03-47 Produced Water

43-02-03-48 Measurement of Oil

43-02-03-48.1 Central Production Facility - Commingling of Production

43-02-03-49 Oil Production Equipment, Dikes, and Seals

43-02-03-50 Tank Cleaning Permit

43-02-03-51 Treating Plant

43-02-03-52 Report of Oil Production

43-02-03-52.1 Report of Gas Produced in Association With Oil

43-02-03-53 Saltwater Handling Facilities

43-02-03-54 Investigative Powers

43-02-03-55 Abandonment of Wells - Suspension of Drilling

43-02-03-56 Underground Disposal of Water [Repealed]

43-02-03-57 Determination of Gas Well Potential

43-02-03-58 Method and Time of Shut-In Pressure Tests [Repealed]

43-02-03-59 Production From Gas Wells to Be Measured and Reported

43-02-03-60 Natural Gas Utilization [Repealed]

43-02-03-60.1 Valuation of Flared Gas

43-02-03-60.2 Flaring Exemption

43-02-03-61 Storage Gas

43-02-03-62 Carbon Dioxide, Coal Bed Methane, Helium, and Nitrogen

43-02-03-63 Regulation of Pools

43-02-03-64 Rate of Producing Wells

43-02-03-65 Authorization for Production, Purchase, and Transportation

43-02-03-66 Application for Allowable on New Oil Wells

43-02-03-67 Oil Proration

43-02-03-68 Gas-Oil Ratio Limitation

43-02-03-69 Allocation of Gas Production

43-02-03-70 Gas Proration Period

43-02-03-71 Adjustment of Gas Allowables

43-02-03-72 Gas Proration Units

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43-02-03-73 Permit for Injection of Gas, Air, or Water [Repealed]

43-02-03-74 Casing and Cementing of Injection Wells [Repealed]

43-02-03-75 Notice of Commencement and Discontinuance of Injection

Operations [Repealed]

43-02-03-76 Records [Repealed]

43-02-03-77 Application for Unitized Management Under Commission

Order

43-02-03-78 Illegal Sale Prohibited [Repealed]

43-02-03-79 Purchase of Liquids From Gas Wells

43-02-03-80 Reports of Purchasers and Transporters of Crude Oil

43-02-03-81 Authorization to Transport Oil From a Well or Central

Production Facility

43-02-03-81.1 Reports of Purchases for Resale and Transporting of Dry Gas

43-02-03-82 Renery Reports

43-02-03-83 Gas Processing Plant Reports

43-02-03-84 Additional Information May Be Required

43-02-03-85 Books and Records to Be Kept to Substantiate Reports

43-02-03-86 Public Hearing Required [Repealed]

43-02-03-87 Institute Proceedings [Repealed]

43-02-03-88 Application for Hearing

43-02-03-88.1 Special Procedures for Increased Density Wells, Pooling,

Flaring Exemption, Underground Injection, Commingling,

Converting Mineral Wells to Freshwater Wells, and Central

Tank Battery or Central Production Facilities Applications

43-02-03-88.2 Hearing Participants by Telephone

43-02-03-89 Upon Application Hearing Is Set [Repealed]

43-02-03-90 Hearings - Complaint Proceedings - Emergency Proceedings

- Other Proceedings

43-02-03-90.1 Investigatory Hearings

43-02-03-90.2 Ofcial Record

43-02-03-90.3 Petitions for Review of Recommended Order and Oral

Arguments Prohibited

43-02-03-90.4 Notice of Order by Mail

43-02-03-90.5 Service and Filing

43-02-03-91 Rehearing [Repealed]

43-02-03-92 Burden of Proof [Repealed]

43-02-03-93 Designation of Examiners

43-02-03-94 Matters to Be Heard by Examiner [Repealed]

43-02-03-95 Powers and Duties of Examiner

43-02-03-96 Matters Heard by Commission [Repealed]

43-02-03-97 Examiner Disinterested Umpire [Repealed]

43-02-03-98 Report of Examiner

43-02-03-99 Commission Order From Examiner Hearing

43-02-03-100 Hearing De Novo Before Commission [Repealed]

43-02-03-101 Prehearing Motion Practice

43-02-03-01. Denitions. The terms used throughout this chapter have the

same meaning as in North Dakota Century Code chapter 38-08 except:

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1. "Adjusted allowable" means the allowable production a proration unit

receives after all adjustments are applied.

2. "Allocated pool" is one in which the total oil or natural gas production is

restricted and allocated to various proration units therein in accordance

with proration schedules.

3. "Allowable production" means that number of barrels of oil or cubic feet

of natural gas authorized to be produced from the respective proration

units in an allocated pool.

4. "Barrel" means forty-two United States gallons [158.99 liters] measured

at sixty degrees Fahrenheit [15.56 degrees Celsius] and fourteen and

seventy-three hundredths pounds per square inch absolute [1034.19

grams per square centimeter].

5. "Barrel of oil" means forty-two United States gallons [158.99 liters] of oil

after deductions for the full amount of basic sediment, water, and other

impurities present, ascertained by centrifugal or other recognized and

customary test.

6. "Bottom hole or subsurface pressure" means the pressure in pounds per

square inch gauge under conditions existing at or near the producing

horizon.

7. "Bradenhead gas well" means any well capable of producing gas

through wellhead connections from a gas reservoir which has been

successfully cased off from an underlying oil or gas reservoir.

8. "Casinghead gas" means any gas or vapor, or both gas and vapor,

indigenous to and produced from a pool classied as an oil pool by the

commission.

9. "Certied or registered mail" means any form of service by the United

States postal service, federal express, Pitney Bowes, and any other

commercial, nationwide delivery service that provides the mailer with a

document showing the date of delivery or refusal to accept delivery.

10. "Common purchaser for natural gas" means any person now or

hereafter engaged in purchasing, from one or more producers, gas

produced from gas wells within each common source of supply from

which it purchases, for processing or resale.

11. "Common purchaser for oil" means every person now engaged or

hereafter engaging in the business of purchasing oil in this state.

12. "Common source of supply" is synonymous with pool and is a common

accumulation of oil or gas, or both, as dened by commission orders.

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13. "Completion" means an oil well shall be considered completed when

the rst oil is produced through wellhead equipment into tanks from the

ultimate producing interval after casing has been run. A gas well shall be

considered complete when the well is capable of producing gas through

wellhead equipment from the ultimate producing zone after casing has

been run. A dry hole shall be considered complete when all provisions

of plugging are complied with as set out in this chapter.

14. "Condensate" means the liquid hydrocarbons recovered at the surface

that result from condensation due to reduced pressure or temperature

of petroleum hydrocarbons existing in a gaseous phase in the reservoir.

15. "Cubic foot of gas" means that volume of gas contained in one cubic

foot [28.32 liters] of space and computed at a pressure of fourteen and

seventy-three hundredths pounds per square inch absolute [1034.19

grams per square centimeter] at a base temperature of sixty degrees

Fahrenheit [15.56 degrees Celsius].

16. "Director" means the director of oil and gas of the industrial commission,

the assistant director of oil and gas of the industrial commission, and

their designated representatives.

17. "Enhanced recovery" means the increased recovery from a pool

achieved by articial means or by the application of energy extrinsic

to the pool, which articial means or application includes pressuring,

cycling, pressure maintenance, or injection to the pool of a substance

or form of energy but does not include the injection in a well of a

substance or form of energy for the sole purpose of:

a. Aiding in the lifting of uids in the well; or

b. Stimulation of the reservoir at or near the well by mechanical,

chemical, thermal, or explosive means.

18. "Exception well location" means a location which does not conform to

the general spacing requirements established by the rules or orders

of the commission but which has been specically approved by the

commission.

19. "Gas lift" means any method of lifting liquid to the surface by injecting

gas into a well from which oil production is obtained.

20. "Gas-oil ratio" means the ratio of the gas produced in cubic feet to a

barrel of oil concurrently produced during any stated period.

21. "Gas-oil ratio adjustment" means the reduction in allowable of a high

gas-oil ratio proration unit to conform with the production permitted

by the limiting gas-oil ratio for the particular pool during a particular

proration period.

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22. "Gas transportation facility" means a pipeline in operation serving one

or more gas wells for the transportation of natural gas, or some other

device or equipment in like operation whereby natural gas produced

from gas wells connected therewith can be transported.

23. "Gas well" means a well producing gas or natural gas from a common

source of gas supply as determined by the commission.

24. "High gas-oil ratio proration unit" means a proration unit with a producing

oil well with a gas-oil ratio in excess of the limiting gas-oil ratio for the

pool.

25. "Injection or input well" means any well used for the injection of air, gas,

water, or other uids into any underground stratum.

26. "Limiting gas-oil ratio" means the gas-oil ratio assigned by the

commission to a particular oil pool to limit the volumes of casinghead

gas which may be produced from the various oil-producing units within

that particular pool.

27. "Log or well log" means a systematic, detailed, and correct record of

formations encountered in the drilling of a well, including commercial

electric logs, radioactive logs, dip meter logs, and other related logs.

28. "Multiple completion" means the completion of any well so as to permit

the production from more than one common source of supply.

29. "Natural gas or gas" means and includes all natural gas and all other

uid hydrocarbons not herein dened as oil.

30. "Occupied dwelling" or "permanently occupied dwelling" means a

residence which is lived in by a person at least six months throughout

a calendar year.

31. "Ofcial gas-oil ratio test" means the periodic gas-oil ratio test made by

order of the commission and by such method and means and in such

manner as prescribed by the commission.

32. "Offset" means a well drilled on a forty-acre [16.19-hectare] tract

cornering or contiguous to a forty-acre [16.19-hectare] tract having

an existing oil well, or a well drilled on a one hundred sixty-acre

[64.75-hectare] tract cornering or contiguous to a one hundred

sixty-acre [64.75-hectare] tract having an existing gas well; provided,

however, that for wells subject to a eldwide spacing order, "offset"

means any wells located on spacing units cornering or contiguous to

the spacing unit or well which is the subject of an inquiry or a hearing.

33. "Oil well" means any well capable of producing oil or oil and casinghead

gas from a common source of supply as determined by the commission.

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34. "Operator" is the principal on the bond covering a well and such person

shall be responsible for drilling, completion, and operation of the well,

including plugging and reclamation of the well site.

35. "Overage or overproduction" means the amount of oil or the amount of

natural gas produced during a proration period in excess of the amount

authorized on the proration schedule.

36. "Potential" means the properly determined capacity of a well to produce

oil, or gas, or both, under conditions prescribed by the commission.

37. "Pressure maintenance" means the injection of gas or other uid into

a reservoir, either to increase or maintain the existing pressure in such

reservoir or to retard the natural decline in the reservoir pressure.

38. "Proration day" consists of twenty-four consecutive hours which shall

begin at seven a.m. and end at seven a.m. on the following day.

39. "Proration month" means the calendar month which shall begin at

seven a.m. on the rst day of such month and end at seven a.m. on

the rst day of the next succeeding month.

40. "Proration schedule" means the periodic order of the commission

authorizing the production, purchase, and transportation of oil or of

natural gas from the various units of oil or of natural gas proration in

allocated pools.

41. "Proration unit for gas" consists of such geographical area as may be

prescribed by special pool rules issued by the commission.

42. "Recomplete" means the subsequent completion of a well in a different

pool.

43. "Reservoir" means pool or common source of supply.

44. "Saltwater handling facility" means and includes any container such

as a pit, tank, or pool, whether covered or uncovered, used for the

handling, storage, disposal of deleterious substances obtained, or used,

in connection with the drilling or operation of wells.

45. "Shut-in pressure" means the pressure noted at the wellhead when the

well is completely shut in, not to be confused with bottom hole pressure.

46. "Spacing unit" is the area in each pool which is assigned to a well

for drilling, producing, and proration purposes in accordance with the

commission’s rules or orders.

47. "Stratigraphic test well" means any well or hole, except a seismograph

shot hole, drilled for the purpose of gathering information in connection

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with the oil and gas industry with no intent to produce oil or gas from

such well.

48. "Tank bottoms" means that accumulation of hydrocarbon material and

other substances which settle naturally below crude oil in tanks and

receptacles that are used in handling and storing of crude oil, and

which accumulation contains basic sediment and water in an amount

rendering it unsalable to an ordinary crude oil purchaser; provided, that

with respect to lease production and for lease storage tanks, a tank

bottom shall be limited to that volume of the tank in which it is contained

that lies below the bottom of the pipeline outlet thereto.

49. "Treating plant" means any plant permanently constructed or portable

used for the purpose of wholly or partially reclaiming, treating,

processing, or in any manner making tank bottoms or any other waste

oils marketable.

History: Amended effective January 1, 1983; May 1, 1992; July 1, 1996;

December 1, 1996; September 1, 2000; July 1, 2002; January 1, 2008.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-02. Scope of chapter. This chapter contains general rules of

statewide application which have been adopted by the industrial commission to

conserve the natural resources of North Dakota, to prevent waste, and to provide

for operation in a manner as to protect correlative rights of all owners of crude oil and

natural gas. Special rules, pool rules, eld rules, and regulations and orders have

been and will be issued when required and shall prevail as against general rules,

regulations, and orders if in conict therewith. However, wherever this chapter

does not conict with special rules heretofore or hereafter adopted, this chapter will

apply in each case. The commission may grant exceptions to this chapter, after

due notice and hearing, when such exceptions will result in the prevention of waste

and operate in a manner to protect correlative rights.

History: Amended effective May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-03. Promulgation of rules, regulations, or orders. Repealed

effective January 1, 1983.

43-02-03-04. Emergency rule, regulation, or order. Repealed effective

January 1, 1983.

43-02-03-05. Enforcement of laws, rules, and regulations dealing with

conservation of oil and gas. The commission, its agents, representatives, and

employees are charged with the duty and obligation of enforcing all rules and

statutes of North Dakota relating to the conservation of oil and gas. However,

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it shall be the responsibility of all the owners or operators to obtain information

pertaining to the regulation of oil and gas before operations have begun.

History: Amended effective May 1, 2004; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-06. Waste prohibited. All operators, contractors, drillers,

carriers, gas distributors, service companies, pipe pulling and salvaging

contractors, or other persons shall at all times conduct their operations in the

drilling, equipping, operating, producing, plugging, and site reclamation of oil and

gas wells in a manner that will prevent waste.

History: Amended effective January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-03

Law Implemented: NDCC 38-08-03

43-02-03-07. United States government leases. The commission

recognizes that all persons drilling and producing on United States government

land shall comply with the United States government regulations. Such persons

shall also comply with all applicable state rules and regulations. Copies of the

sundry notices, reports on wells, and well data required by this chapter of the wells

on United States government land shall be furnished to the commission at no

expense to the commission. Federal forms may be used when ling such notices

and reports except for reporting the plugging and abandonment of a well. In such

instance, the plugging record (form 7) must be led with the commission.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1994.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-08. Classifying and dening pools. Repealed effective

January 1, 1983.

43-02-03-09. Forms upon request. Forms for written notices, requests,

and reports required by the commission will be furnished upon request. These

forms shall be of such nature as prescribed by the commission to cover proposed

work and to report the results of completed work.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-10. Authority to cooperate with other agencies. The

commission may from time to time enter into arrangements with state and federal

government agencies, industry committees, and individuals with respect to special

projects, services, and studies relating to conservation of oil and gas.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

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43-02-03-11. Organization reports. Every person acting as principal or

agent for another or independently engaged in the drilling of oil or gas wells, or in

the production, storage, transportation, rening, reclaiming, treating, marketing, or

processing of crude oil or natural gas in North Dakota shall immediately le with the

director the name under which such business is being conducted or operated; and

name and post-ofce address of such person, the business or businesses in which

the person is engaged; the plan of organization, and in case of a corporation, the

law under which it is chartered; and the names and post-ofce addresses of any

person acting as trustee, together with the names and post-ofce addresses of

any ofcials thereof on an organization report (form 2). In each case where such

business is conducted under an assumed name, such organization report shall

show the names and post-ofce addresses of all owners in addition to the other

information required. A new organization report shall be led when and if there is

a change in any of the information contained in the original report.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-12. Reservoir surveys. By special order of the commission,

periodic surveys may be made of the reservoirs in this state containing oil and gas.

These surveys will be thorough and complete and shall be made using methods

approved by the director. The condition of the reservoirs containing oil and gas and

the practices and methods employed by the operators shall be investigated. The

produced volume and source of crude oil and natural gas, the reservoir pressure of

the reservoir as an average, the areas of regional or differential pressure, stabilized

gas-oil ratios, and the producing characteristics of the eld as a whole and the

individual wells within the eld shall be specically included.

All operators of oil wells are required to permit and assist the agents of

the commission in making any and all special tests that may be required by the

commission on any or all wells.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-13. Record of wells. The director shall maintain a record of ofcial

well names, to be known as the well-name register, in which shall be entered: (1)

the name and location of each well; (2) the well le number; (3) the name of the

operator, or the operator’s agent; and (4) any subsequent name or names assigned

to the well and approved by the director.

The last name assigned to a well in the well-name register shall be the ofcial

name of the well, and the one by which it shall be known and referred to.

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The director may, at the director’s discretion, grant or refuse an application

to change the ofcial name. The application shall be accompanied by a fee of

twenty-ve dollars, which fee is established to cover the expense of recording the

change. If the application is refused, the fee shall be refunded.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-14. Access to records. The commission, director, and their

representatives shall have access to all well records wherever located. All owners,

operators, drilling contractors, drillers, service companies, or other persons

engaged in drilling, completing, producing, or servicing wells shall permit the

commission, director, and their representatives to come upon any lease, property,

well, or drilling rig operated or controlled by them, complying with state safety

rules, and to inspect the records and operation of such wells, and to have access

at all times to any and all records of wells. If requested, copies of such records

must be led with the commission. The condentiality of any data submitted which

is condential pursuant to subsection 6 of North Dakota Century Code section

38-08-04 and section 43-02-03-31 must be maintained.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1,

1994.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-14.1. Verication of certied welders. Repealed effective

July 1, 1996.

43-02-03-14.2. Oil and gas metering systems.

1. Application of section. This section is applicable to all metering

stations measuring production from oil and gas wells within the state of

North Dakota, including private, state, and federal wells. If these rules

differ from federal requirements on measurement of production from

federal oil and gas wells, the federal rules take precedence.

2. Denitions. As used in this section:

a.

"Allocation meter" means a meter used by the producer to

determine the volume from an individual well before it is

commingled with production from one or more other wells

prior to the custody transfer point.

b. "Calibration test" means the process or procedure of adjusting an

instrument, such as a gas meter, so its indication or registration is

in satisfactorily close agreement with a reference standard.

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c.

"Custody transfer meter" means a meter used to transfer oil or gas

from the producer to transporter or purchaser.

d. "Gas gathering meter" means a meter used in the custody transfer

of gas into a gathering system.

e.

"Meter factor" means a number obtained by dividing the net volume

of uid (liquid or gaseous) passed through the meter during proving

by the net volume registered by the meter.

f. "Metering proving" means the procedure required to determine the

relationship between the true volume of a uid (liquid or gaseous)

measured by a meter and the volume indicated by the meter.

3. Inventory ling requirements. The owner of metering equipment

shall le with the commission an inventory of all meters used for

custody transfer and allocation of production from oil or gas wells, or

both. Inventories must be updated on an annual basis, and led with

the commission on or before the rst day of each year, or they may

be updated as frequently as monthly, at the discretion of the operator.

Inventories must include the following:

a. Well name and legal description of location or meter location if

different.

b. North Dakota industrial commission well le number.

c. Meter information:

(1) Gas meters:

(a) Make and model.

(b) Differential, static, and temperature range.

(c) Orice tube size (diameter).

(d) Meter station number.

(2) Oil meters:

(a) Make and model.

(b) Size.

(c) Meter station number.

4. Installation and removal of meters. The commission must be notied

of all custody transfer meters placed in service. The owner of the

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custody transfer equipment shall notify the commission of the date a

meter is placed in service, the make and model of the meter, and the

meter or station number. The commission must also be notied of all

metering installations removed from service. The notice must include

the date the meter is removed from service and the meter or station

number. The required notices must be led with the commission within

thirty days of the installation or removal of a meter.

All allocation meters must be approved prior to installation and use. The

application for approval must be on a sundry notice (form 4) and shall

include the make and model number of the meter, the meter or station

number, the well name, its location, and the date the meter will be placed

in service.

Meter installations for measuring production from oil or gas wells, or

both, must be constructed to American petroleum institute or American

gas association standards or to meter manufacturer’s recommended

installation. Meter installations constructed in accordance with

American petroleum institute or American gas association standards in

effect at the time of installation shall not automatically be required to

retrot if standards are revised. The commission will review any revised

standards, and when deemed necessary will amend the requirements

accordingly.

5. Registration of persons proving or testing meters. All persons

engaged in meter proving or testing of oil and gas meters must be

registered with the commission. Those persons involved in oil meter

testing, by owing uid through the meter into a test tank and then

gauging the tank, are exempted from the registration process. However,

such persons must notify the commission prior to commencement of

the test to allow a representative of the commission to witness the

testing process. A report of the results of such test shall be led with the

commission within thirty days after the test is completed. Registration

must include the following:

a. Name and address of company.

b. Name and address of measurement personnel.

c. Qualications, listing experience or specic training.

Any meter tests performed by a person not registered with the

commission will not be accepted as a valid test.

6. Calibration requirements. Oil and gas metering equipment must

be proved or tested to American petroleum institute or American gas

association standards or to the meter manufacturer’s recommended

procedure to establish a meter factor or to ensure measurement

accuracy. The owner of a custody transfer meter or allocation meter

13 4/2012
shall notify the commission at least ten days prior to the testing of any

meter.

a. Oil allocation meter factors shall be maintained within two percent

of original meter factor. If the factor change between provings or

tests is greater than two percent, the meter must be repaired or

adjusted and tested within forty-eight hours of repair or replaced.

b. Copies of all oil allocation meter test procedures are to be led with

and reviewed by the commission to ensure measurement accuracy.

c. All gas meters must be tested with a minimum of a three-point test

for static and differential pressure elements and a two-point test for

temperature elements. The test reports must include an as-found

and as-left test and a detailed report of changes.

d. Test reports must include the following:

(1) Producer name.

(2) Lease name.

(3) Pipeline company or company name of test contractor.

(4) Test personnel’s name.

(5) Station or meter number.

e. Unless required more often by the director, minimum frequency of

meter proving or calibration tests are as follows:

(1) Oil meters used for custody transfer shall be proved monthly

for all measured volumes which exceed two thousand barrels

per month. For volumes two thousand barrels or less per

month, meters shall be proved at each two thousand barrel

interval or more frequently at the discretion of the operator.

(2) Quarterly for oil meters used for allocation of production.

(3) Semiannually for gas meters used for allocation of

production.

(4) Semiannually for gas meters in gas gathering systems.

(5) For meters measuring more than one hundred thousand

cubic feet [2831.68 cubic meters] per day on a monthly basis,

orice plates shall be inspected semiannually, and meter

tubes shall be inspected at least every ve years to ensure

4/2012 14
continued conformance with the American gas association

meter tube specications.

(6) For meters measuring one hundred thousand cubic feet

[2831.68 cubic meters] per day or less on a monthly basis,

orice plates shall be inspected annually.

f. Meter test reports must be led within thirty days of completion of

proving or calibration tests unless otherwise approved. Test reports

are to be led on, but not limited to, all meters used for allocation

measurement of oil or gas and all meters used in crude oil custody

transfer.

g. Accuracy of all equipment used to test oil or gas meters must be

traceable to the standards of the national institute of standards and

technology. The equipment must be certied as accurate either by

the manufacturer or an independent testing facility. The certicates

of accuracy must be made available upon request. Certication of

the equipment must be updated as follows:

(1) Annually for all equipment used to test the pressure and

differential pressure elements.

(2) Annually for all equipment used to determine temperature.

(3) Biennially for all conventional pipe provers.

(4) Annually for all master meters.

(5) Five years for equipment used in orice tube inspection.

7. Variances. Variances from all or part of this section may be granted

by the commission on the basis of economic necessity providing the

variance does not affect measurement accuracy. All requests for

variances must be on a sundry notice (form 4).

A register of variances requested and approved must be maintained by

the commission.

History: Effective May 1, 1994; amended effective July 1, 1996; September 1,

2000; July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-15. Bond and transfer of wells.

1. Bond requirements. Prior to commencing drilling operations, any

person who proposes to drill a well for oil, gas, or injection shall submit

to the commission, and obtain its approval, a surety bond or cash bond.

15 4/2012
An alternative form of security may be approved by the commission

after notice and hearing, as provided by law. The operator of such

well shall be the principal on the bond covering the well. Each surety

bond shall be executed by a responsible surety company authorized to

transact business in North Dakota.

2. Bond amounts and limitations. The bond shall be in the amount of

fty thousand dollars when applicable to one well only. Wells drilled to a

total depth of less than two thousand feet [609.6 meters] may be bonded

in a lesser amount if approved by the director. When the principal on

the bond is drilling or operating a number of wells within the state or

proposes to do so, the principal may submit a bond conditioned as

provided by law. Wells utilized for commercial disposal operations must

be bonded in the amount of fty thousand dollars. A blanket bond

covering more than one well shall be in the amount of one hundred

thousand dollars, provided the bond shall be limited to no more than six

of the following in aggregate:

a. A well that is a dry hole and is not properly plugged;

b. A well that is plugged and the site is not properly reclaimed; and

c. A well that is abandoned pursuant to section 43-02-03-55 and is

not properly plugged and the site is not properly reclaimed.

If this aggregate of wells is reached, all well permits, for which drilling

has not commenced, held by the principal of such bond are suspended.

No rights may be exercised under the permits until the aggregate of

wells drops below the required limit, or the operator les the appropriate

bond to cover the permits, at which time the rights given by the drilling

permits are reinstated. A well with an approved temporary abandoned

status shall have the same status as an oil, gas, or injection well. The

commission may, after notice and hearing, require higher bond amounts

than those referred to in this section. Such additional amounts for bonds

must be related to the economic value of the well or wells and the

expected cost of plugging and well site reclamation, as determined by

the commission. The commission may refuse to accept a bond or to add

wells to a blanket bond if the operator or surety company has failed in the

past to comply with statutes, rules, or orders relating to the operation

of wells; if a civil or administrative action brought by the commission

is pending against the operator or surety company; or for other good

cause.

3. Unit bond requirements. Prior to commencing unit operations, the

operator of any area under unitized management shall submit to the

commission, and obtain its approval, a surety bond or cash bond. An

alternative form of security may be approved by the commission after

notice and hearing, as provided by law. The operator of the unit shall

be the principal on the bond covering the unit. The amount of the bond

4/2012 16
shall be specied by the commission in the order approving the plan of

unitization. Each surety bond shall be executed by a responsible surety

company authorized to transact business in North Dakota.

Prior to transfer of a unit to a new operator, the commission, after notice

and hearing, may revise the bond amount for a unit, or in the case when

the unit was not previously bonded, the commission may require a bond

and set a bond amount for the unit.

4. Bond terms. Bonds shall be conditioned upon full compliance with

North Dakota Century Code chapter 38-08, and all administrative rules

and orders of the commission. It shall be a plugging bond, as well as

a drilling bond, and is to endure up to and including approved plugging

of all oil, gas, and injection wells as well as dry holes. Approved

plugging shall also include practical reclamation of the well site and

appurtenances thereto. If the principal does not satisfy the bond’s

conditions, then the surety shall satisfy the conditions or forfeit to the

commission the face value of the bond.

5. Transfer of wells under bond. Transfer of property does not release

the bond. In case of transfer of property or other interest in the well and

the principal desires to be released from the bond covering the well,

such as producers, not ready for plugging, the principal must proceed

as follows:

a. The principal must notify the director, in writing, of all proposed

transfers of wells at least thirty days before the closing date of the

transfer. The director may, for good cause, waive this requirement.

The principal shall submit to the commission a form 15 reciting that

a certain well, or wells, describing each well by quarter-quarter,

section, township, and range, is to be transferred to a certain

transferee, naming such transferee, for the purpose of ownership

or operation. The date of assignment or transfer must be stated

and the form signed by a party duly authorized to sign on behalf

of the principal.

On said transfer form the transferee shall recite the following: "The

transferee has read the foregoing statement and does accept such

transfer and does accept the responsibility of such well under the

transferee’s one-well bond or, as the case may be, does accept

the responsibility of such wells under the transferee’s blanket bond,

said bond being tendered to or on le with the commission." Such

acceptance must likewise be signed by a party authorized to sign

on behalf of the transferee and the transferee’s surety.

b. When the commission has passed upon the transfer and

acceptance and accepted it under the transferee’s bond, the

transferor shall be released from the responsibility of plugging

17 4/2012
the well and site reclamation. If such wells include all the wells

within the responsibility of the transferor’s bond, such bond will

be released by the commission upon written request. Such

request must be signed by an ofcer of the transferor or a person

authorized to sign for the transferor. The director may refuse to

transfer any well from a bond if the well is in violation of a statute,

rule, or order.

c. The transferee (new operator) of any oil, gas, or injection well shall

be responsible for the plugging and site reclamation of any such

well. For that purpose the transferee shall submit a new bond or, in

the case of a surety bond, produce the written consent of the surety

of the original or prior bond that the latter’s responsibility shall

continue and attach to such well. The original or prior bond shall

not be released as to the plugging and reclamation responsibility

of any such transferor until the transferee shall submit to the

commission an acceptable bond to cover such well. All liability

on bonds shall continue until the plugging and site reclamation of

such wells is completed and approved.

6. Treating plant bond. Prior to the commencement of operations,

any person proposing to operate a treating plant must submit to the

commission and obtain its approval of a surety bond or cash bond. An

alternative form of security may be approved by the commission after

notice and hearing, as provided by law. The person responsible for the

operation of the plant shall be the principal on the bond. Each surety

bond shall be executed by a responsible surety company authorized

to transact business in North Dakota. The amount of the bond must

be as prescribed in section 43-02-03-51. It is to remain in force until

the operations cease, all equipment is removed from the site, and the

site and appurtenances thereto are reclaimed, or liability of the bond is

transferred to another bond that provides the same degree of security.

If the principal does not satisfy the bond’s conditions, then the surety

shall satisfy the conditions or forfeit to the commission the face value

of the bond.

7. Bond termination. The commission shall, in writing, advise the

principal and any sureties on any bond as to whether the plugging and

reclamation is approved. If approved, liability under such bond may be

formally terminated upon receipt of a written request by the principal.

The request must be signed by an ofcer of the principal or a person

authorized to sign for the principal.

8. Director’s authority. The director is vested with the power to act for

the commission as to all matters within this section, except requests

4/2012 18
for alternative forms of security, which may only be approved by the

commission.

History: Amended effective April 30, 1981; March 1, 1982; January 1, 1983; May 1,

1990; May 1, 1992; May 1, 1994; July 1, 1996; December 1, 1996; September 1,

2000; July 1, 2002; May 1, 2004; January 1, 2006; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-16. Application for permit to drill and recomplete. Before any

person shall begin any well-site preparation for the drilling of any well other than

surveying and staking, such person shall le an application for permit to drill (form 1)

with the director, together with a permit fee of one hundred dollars. Verbal approval

may be given for site preparation by the director in extenuating circumstances. No

drilling activity shall commence until such application is approved and a permit to

drill is issued by the director. The application must be accompanied by the bond

pursuant to section 43-02-03-15 or the applicant must have previously led such

bond with the commission, otherwise the application is incomplete. An incomplete

application received by the commission has no standing and will not be deemed

led until it is completed.

The application for permit to drill shall be accompanied by an accurate

plat certied by a registered surveyor showing the location of the proposed well

with reference to true north and the nearest lines of a governmental section. The

plat shall also include latitude and longitude of the proposed well location to the

nearest tenth of a second. Information to be included in such application shall be

the proposed depth to which the well will be drilled, estimated depth to the top of

important markers, estimated depth to the top of objective horizons, the proposed

mud program, the proposed casing program, including size and weight thereof, the

depth at which each casing string is to be set, the proposed pad layout, including

cut and ll diagrams, and the proposed amount of cement to be used, including

the estimated top of cement.

Prior to the commencement of recompletion operations or drilling

horizontally in the existing pool, an application for permit shall be led with the

director. Included in such application shall be the notice of intention (form 4) to

reenter a well by drilling horizontally, deepening, or plugging back to any source

of supply other than the producing horizon in an existing well. Such notice shall

include the name and le number and exact location of the well, the approximate

date operations will begin, the proposed procedure, the estimated completed

total depth, the anticipated hydrogen sulde content in produced gas from the

proposed source of supply, the weight and grade of all casing currently installed

in the well unless waived by the director, the casing program to be followed, and

the original total depth with a permit fee of fty dollars. The director may deny any

application if it is determined, in accordance with the latest version of ANSI/NACE

MR0175/ISO 15156, that the casing currently installed in the well would be subject

to sulde stress cracking.

19 4/2012
The applicant shall provide all information, in addition to that specically

required by this section, if requested by the director. The director may impose

such terms and conditions on the permits issued under this section as the director

deems necessary.

The director shall deny an application for a permit under this section if the

proposal would cause, or tend to cause, waste or violate correlative rights. The

director of oil and gas shall state in writing to the applicant the reason for the

denial of the permit. The applicant may appeal the decision of the director to the

commission.

A permit to drill automatically expires one year after the date it was issued,

unless the well is drilling or has been drilled below surface casing. A permit to

recomplete or to drill horizontally automatically expires one year after the date it

was issued, unless such project has commenced.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1,

1994; September 1, 2000; July 1, 2002; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-05

Law Implemented: NDCC 38-08-05

43-02-03-16.1. Designation and responsibilities of operator. The

principal on the bond covering a well is the operator of the well. The operator is

responsible for compliance with all laws relating to the well and well site. A dispute

over designation of the operator of a well may be addressed by the commission.

In doing so, the factors the commission may consider include those set forth in

subsection 1 of section 43-02-03-16.2.

History: Effective December 1, 1996.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-16.2. Revocation and limitation of drilling permits.

1. After notice and hearing, the commission may revoke a drilling,

recompletion, or reentry permit or limit its duration. The commission

may act upon its own motion or upon the application of an owner in the

spacing or drilling unit. In deciding whether to revoke or limit a permit,

the factors that the commission may consider include:

a. The technical ability of the permitholder and other owners to drill

and complete the well.

b. The experience of the permitholder and other owners in drilling and

completing similar wells.

c. The number of wells in the area operated by the permitholder and

other owners.

4/2012 20
d. Whether drainage of the spacing or drilling unit has occurred or is

likely to occur in the immediate future and whether the permitholder

has committed to drill a well in a timely fashion.

e. Contractual obligations such as an expiring lease.

f. The amount of ownership the permitholder and other owners hold in

the spacing or drilling unit. If the permitholder is the majority owner

in the unit or if its interest when combined with that of its supporters

is a majority of the ownership, it is presumed that the permitholder

should retain the permit. This presumption, even if not rebutted,

does not prohibit the commission from limiting the duration of the

permit. However, if the amount of the interest owned by the owner

seeking revocation or limitation and its supporters are a majority of

the ownership, the commission will presume that the permit should

be revoked.

2. The commission may suspend a permit that is the subject of a

revocation or limitation proceeding. A permit will not be suspended or

revoked after operations have commenced.

3. If the commission revokes a permit upon the application of an owner

and issues a permit to that owner or to another owner who supported

revocation, the commission may limit the duration of such permit. The

commission may also, if the parties fail to agree, order the owner

acquiring the permit to pay reasonable costs incurred by the former

permitholder and the conditions under which payment is to be made.

The costs for which reimbursement may be ordered may include those

involving survey of the well site, title search of surface and mineral title,

and preparation of an opinion of mineral ownership.

4. If the commission declines to revoke a permit or limit the time within

which it must be exercised, it may include a term in its order restricting

the ability of the permitholder to renew the permit or to acquire another

permit within the same spacing or drilling unit.

History: Effective December 1, 1996; amended effective January 1, 2006.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-16.3. Recovery of a risk penalty. The following govern the

recovery of the risk penalty pursuant to subsection 3 of North Dakota Century

Code section 38-08-08 and subsection 3 of North Dakota Century Code section

38-08-09.4:

1. An owner may recover the risk penalty under the provisions of

subsection 3 of North Dakota Century Code section 38-08-08, provided

the owner gives, to the owner from whom the penalty is sought, a

written invitation to participate in the risk and cost of drilling a well,

21 4/2012
including reentering a plugged and abandoned well, or the risk and

cost of reentering an existing well to drill deeper or a horizontal lateral.

If the nonparticipating owner’s interest is not subject to a lease or other

contract for development, an owner seeking to recover a risk penalty

must also make a good-faith attempt to have the unleased owner

execute a lease.

a. The invitation to participate in drilling must contain the following:

(1) The approximate location of the proposed or existing well and

its proposed depth and objective zone.

(2) An itemization of the estimated costs of drilling and

completion.

(3) The approximate date upon which the well was or will be

spudded or reentered.

(4) A statement indicating the invitation must be accepted within

thirty days of receiving it.

(5) Notice that the participating owners plan to impose a risk

penalty and that the nonparticipating owner may object to the

risk penalty by either responding in opposition to the petition

for a risk penalty, or if no such petition has been led, by ling

an application or request for hearing with the commission.

(6) Drilling or spacing unit description.

b. An election to participate must be in writing and must be received by

the owner giving the invitation within thirty days of the participating

party’s receipt of the invitation.

c. An invitation to participate and an election to participate must

be served personally, by mail requiring a signed receipt, or by

overnight courier or delivery service requiring a signed receipt.

Failure to accept mail requiring a signed receipt constitutes service.

d. An election to participate is only binding upon an owner electing

to participate if the well is spudded or reentry operations are

commenced on or before ninety days after the date the owner

extending the invitation to participate sets as the date upon which

a response to the invitation is to be received. It also expires if the

permit to drill or reenter expires without having been exercised.

If an election to participate lapses, a risk penalty can only be

collected if the owner seeking it again complies with the provisions

of this section.

4/2012 22
2. An owner may recover the risk penalty under the provisions of

subsection 3 of North Dakota Century Code section 38-08-09.4,

provided the owner gives, to the owner from whom the penalty is

sought, a written invitation to participate in the unit expense. If the

nonparticipating owner’s interest is not subject to a lease or other

contract for development, an owner seeking to recover a risk penalty

must also make a good-faith attempt to have the unleased owner

execute a lease.

a. The invitation to participate in the unit expense must contain the

following:

(1) A description of the proposed unit expense, including the

location, objectives, and plan of operation.

(2) An itemization of the estimated costs.

(3) The approximate date upon which the proposal was or will be

commenced.

(4) A statement indicating the invitation must be accepted within

thirty days of receiving it.

(5) Notice that the participating owners plan to impose a risk

penalty and that the nonparticipating owner may object to the

risk penalty by either responding in opposition to the petition

for a risk penalty, or if no such petition has been led, by ling

an application or request for hearing with the commission.

b. An election to participate must be in writing and must be received by

the owner giving the invitation within thirty days of the participating

party’s receipt of the invitation.

c. An invitation to participate and an election to participate must

be served personally, by mail requiring a signed receipt, or by

overnight courier or delivery service requiring a signed receipt.

Failure to accept mail requiring a signed receipt constitutes service.

d. An election to participate is only binding upon an owner electing

to participate if the unit expense is commenced within ninety

days after the date the owner extending the invitation request to

participate sets as the date upon which a response to the request

invitation is to be received. If an election to participate lapses, a

risk penalty can only be collected if the owner seeking it again

complies with the provisions of this section.

e. An invitation to participate in a unit expense covering monthly

operating expenses shall be effective for all such monthly operating

expenses for a period of ve years if the unit expense identied in

23 4/2012
the invitation to participate is rst commenced within ninety days

after the date set in the invitation to participate as the date upon

which a response to the invitation to participate must be received.

An election to participate in a unit expense covering monthly

operating expenses is effective for ve years after operations are

rst commenced. If an election to participate in a unit expense

comprised of monthly operating expenses expires or lapses after

ve years, a risk penalty may only be assessed and collected if the

owner seeking the penalty once again complies with this section.

3. Upon its own motion or the request of a party, the commission may

include in a pooling order requirements relating to the invitation and

election to participate, in which case the pooling order will control to the

extent it is inconsistent with this section.

History: Effective December 1, 1996; amended effective May 1, 2004; January 1,

2006; January 1, 2008; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04, 38-08-08

43-02-03-17. Sign on well. Every well associated with the production of oil

and gas except plugged wells shall be identied by a sign posted on the derrick or

not more than twenty feet [6.10 meters] from the well. The sign shall be of durable

construction and the lettering thereon shall be kept in a legible condition and shall be

large enough to be legible under normal conditions at a distance of fty feet [15.24

meters]. The wells on each lease or property shall be numbered in nonrepetitive

sequence, unless some other system of numbering was adopted by the owner prior

to the adoption of this chapter. Each sign must show the well name and number

(which shall be different or distinctive for each well), the name of the operator, le

number, and the location by quarter-quarter, section, township, and range.

Existing well identication signs that are otherwise in accord with this section

except that well locations are shown by quarter section rather than quarter-quarter

section or show the permit number rather than the le number shall be allowed to

remain.

History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-18. Drilling units - Well locations. In the absence of an order by

the commission setting spacing units for a pool:

1. a. Vertical or directional oil wells projected to a depth not deeper

than the Mission Canyon formation must be drilled upon a

governmental quarter-quarter section or equivalent lot, located

not less than ve hundred feet [152.4 meters] to the boundary of

such governmental quarter-quarter section or equivalent lot. No

more than one well shall be drilled to the same pool on any such

4/2012 24
governmental quarter-quarter section or equivalent lot, except by

order of the commission, nor shall any well be drilled on any such

governmental quarter-quarter section or equivalent lot containing

less than thirty-six acres [14.57 hectares] except by order of the

commission.

b. Vertical or directional oil wells projected to a depth deeper than

the Mission Canyon formation must be drilled on a governmental

quarter section or equivalent lots, located not less than six hundred

sixty feet [201.17 meters] to the boundary of such governmental

quarter section or equivalent lots. No more than one well shall be

drilled to the same pool on any such governmental quarter section

or equivalent lots, except by order of the commission, nor shall

any well be drilled on any such governmental quarter section or

equivalent lots containing less than one hundred forty-ve acres

[58.68 hectares] except by order of the commission.

2. a. Horizontal wells with a horizontal displacement of the well bore

drilled at an angle of at least eighty degrees within the productive

formation of at least ve hundred feet [152.4 meters], projected to

a depth not deeper than the Mission Canyon formation, must be

drilled upon a drilling unit described as a governmental section or

described as two adjacent governmental quarter sections within the

same section or equivalent lots, located not less than ve hundred

feet [152.4 meters] to the outside boundary of such tract. The

horizontal well proposed to be drilled must, in the director’s opinion,

justify the creation of such drilling unit. No more than one well may

be drilled to the same pool on any such tract, except by order of

the commission.

b. Horizontal wells with a horizontal displacement of the well bore

drilled at an angle of at least eighty degrees within the productive

formation of at least ve hundred feet [152.4 meters], projected

to a depth deeper than the Mission Canyon formation, must be

drilled upon a drilling unit described as a governmental section,

located not less than ve hundred feet [152.4 meters] to the outside

boundary of such tract. The horizontal well proposed to be drilled

must, in the director’s opinion, justify the creation of such drilling

unit. No more than one well may be drilled to the same pool on any

such tract, except by order of the commission.

3. a. Gas wells projected to a depth not deeper than the Mission Canyon

formation shall be drilled upon a governmental quarter section

or equivalent lots, located not less than ve hundred feet [152.4

meters] to the boundary of such governmental quarter section or

equivalent lots. No more than one well shall be drilled to the same

pool on any such governmental quarter section or equivalent lots,

except by order of the commission, nor shall any well be drilled on

any such governmental quarter section or equivalent lot containing

25 4/2012
less than one hundred forty-ve acres [58.68 hectares] except by

order of the commission.

b. Gas wells projected to a depth deeper than the Mission Canyon

formation shall be drilled upon a governmental quarter section or

equivalent lots, located not less than six hundred sixty feet [201.17

meters] to the boundary of such governmental quarter section or

equivalent lots. No more than one well shall be drilled to the same

pool on any such governmental quarter section or equivalent lots,

except by order of the commission, nor shall any well be drilled on

any such governmental quarter section or equivalent lot containing

less than one hundred forty-ve acres [58.68 hectares] except by

order of the commission.

4. Within thirty days, or a reasonable time thereafter, following the

discovery of oil or gas in a pool not then covered by an order of

the commission, a spacing hearing shall be docketed. Following

such hearing the commission shall issue an order prescribing a

temporary spacing pattern for the development of the pool. This

order shall continue in force for a period of not more than three years

at the expiration of which time a hearing shall be held at which the

commission may require the presentation of such evidence as will

enable the commission to determine the proper spacing for the pool.

During the interim period between the discovery and the issuance of the

temporary order, no permits shall be issued for the drilling of an offset

well to the discovery well, unless approved by the director. Approval

shall be consistent with anticipated spacing for the orderly development

of the pool.

Any well drilled within one mile [1.61 kilometers] of an established eld

shall conform to the spacing requirements in that eld except when it is

apparent that the well will not produce from the same common source

of supply. In order to assure uniform and orderly development, any well

drilled within one mile [1.61 kilometers] of an established eld boundary

shall conform to the spacing and special eld rules for the eld, and

for the purposes of spacing and pooling, the eld boundary shall be

extended to include the spacing unit for such well and any intervening

lands. The foregoing shall not be applicable if it is apparent that the

well will not produce from the same common source of supply as wells

within the eld.

4/2012 26
5. If the director denies an application for permit, the director shall advise

the applicant immediately of the reasons for denial. The decision of the

director may be appealed to the commission.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1,

1994; July 1, 1996; July 1, 2002; January 1, 2006; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04, 38-08-07

Law Implemented: NDCC 38-08-04, 38-08-07

43-02-03-18.1. Exception location. If upon application for an exception

location, the commission nds that a well drilled at the location prescribed by any

applicable rule or order of the commission would not produce in paying quantities,

that surface conditions would substantially add to the burden or hazard of such

well, or that the drilling of such well at a location other than the prescribed location is

otherwise necessary either to protect correlative rights, to prevent waste, or to effect

greater ultimate recovery from oil and gas, the commission may enter an order,

after notice and hearing, permitting the well to be drilled at a location other than

that prescribed and shall include in such order suitable provisions to prevent the

production from that well of more than its just and equitable share of the oil and gas

in the pool. The application for an exception well location shall set forth the names of

the lessees of adjoining properties and the names of any unleased mineral owners

of the adjoining properties. The application shall be accompanied by a plat or sketch

accurately showing the property for which the exception well location is sought, the

location of the proposed well, and all other completed and drilling wells on this

property and on the adjoining properties. The applicant or its attorney shall certify

that a copy of the application has been sent to all lessees and all unleased mineral

owners of properties adjoining the tract which would be affected by the exception

location. If the applicant is the lessee of adjoining tracts that would be affected by

the exception, the applicant must give notice, as prescribed above, to its lessors of

such tracts.

History: Effective January 1, 1983; amended effective May 1, 1990; May 1, 1994;

July 1, 1996; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-07

Law Implemented: NDCC 38-08-04, 38-08-07

43-02-03-19. Site construction. In the construction of a drill site, access

road, and all associated facilities, the topsoil shall be removed, stockpiled, and

stabilized or otherwise reserved for use when the area is reclaimed. "Topsoil"

means the suitable plant growth material on the surface; however, in no event shall

this be deemed to be more than the top eight inches [20.32 centimeters] of soil. Soil

stabilization additives and materials to be used onsite, access roads, or associated

facilities must have approval from the director before application.

When necessary to prevent pollution of the land surface and freshwaters,

the director may require the drill site to be sloped and diked.

27 4/2012
Well sites and associated facilities shall not be located in, or hazardously

near, bodies of water, nor shall they block natural drainages. Sites and associated

facilities shall be designed to divert surface drainage from entering the site.

Well sites and associated facilities or appropriate parts thereof shall be

fenced if required by the director.

Within six months after the completion of a well, the portion of the well site

not used for well operations shall be reclaimed, unless waived by the director. Well

sites and all associated facilities shall be stabilized to prevent erosion.

History: Amended effective March 1, 1982; January 1, 1983; May 1, 1992; July 1,

2002; January 1, 2008; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-19.1. Fencing, screening, and netting of drilling and reserve

pits. All open pits and ponds which contain saltwater must be fenced. All pits and

ponds which contain oil must be fenced, screened, and netted.

This is not to be construed as requiring the fencing, screening, or netting

of a drilling pit or reserve pit used solely for drilling, completing, recompleting, or

plugging unless such pit is not reclaimed within ninety days after completion of

drilling operations.

History: Effective May 1, 1992; amended effective April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-19.2. Disposal of waste material. All waste material associated

with exploration or production of oil and gas must be properly disposed of in an

authorized facility in accord with all applicable local, state, and federal laws and

regulations.

All waste material recovered from spills, leaks, and other such events shall

immediately be disposed of in an authorized facility, although the remediation of

such material may be allowed onsite if approved by the director.

This is not to be construed as requiring the offsite disposal of drilling mud

from shallow wells or drill cuttings associated with the drilling of a well. However,

water remaining in a drilling or reserve pit used in the drilling and completion

operations is to be removed from the pit and disposed of in an authorized disposal

well or used in a manner approved by the director. The disposition or use of

4/2012 28
the water must be included on the sundry notice (form 4) reporting the plan of

reclamation pursuant to sections 43-02-03-19.4 and 43-02-03-19.5.

History: Effective May 1, 1992; amended effective May 1, 1994; September 1,

2000; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-19.3. Earthen pits and open receptacles. Except as otherwise

provided in section 43-02-03-19, no saltwater, drilling mud, crude oil, waste oil,

or other waste shall be stored in earthen pits or open receptacles except in an

emergency and upon approval by the director.

A lined earthen pit or open receptacle may be temporarily used to retain

oil, water, cement, solids, or uids generated in well completion, servicing, or

plugging operations. A pit or receptacle used for this purpose must be sufciently

impermeable to provide adequate temporary containment of the oil, water, or uids.

The contents of the pit or receptacle must be removed within seventy-two hours

after operations have ceased and must be disposed of at an authorized facility

in accordance with section 43-02-03-19.2. Within thirty days after operations

have ceased, the earthen pit shall be reclaimed and the open receptacle shall be

removed. The director may grant an extension of the thirty-day time period to no

more than one year for good reason.

The director may permit pits or receptacles used solely for the purpose of

aring casinghead gas. A pit or receptacle used for this purpose must be sufciently

impermeable to provide adequate temporary containment of uids. Permission for

such pit or receptacle shall be conditioned on locating the pit not less than one

hundred fty feet [45.72 meters] from the vicinity of wells and tanks and keeping it

free of any saltwater, crude oil, waste oil, or other waste. Saltwater, drilling mud,

crude oil, waste oil, or other waste shall be removed from the pit or receptacle within

twenty-four hours after being discovered and must be disposed of at an authorized

facility in accordance with section 43-02-03-19.2.

The director may permit pits used solely for storage of freshwater used in

completion and well servicing operations. Permits for freshwater pits shall be valid

for a period of one year but may be reauthorized upon application. Freshwater pits

shall be lined and no pit constructed for this purpose shall be wholly or partially

constructed in ll dirt unless approved by the director. The director may approve

chemical treatment to municipal drinking water standards upon application. The

freshwater pit shall have signage on all sides accessible to vehicular trafc clearly

identifying the usage as freshwater only.

History: Effective September 1, 2000; amended effective April 1, 2010; April 1,

2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

29 4/2012
43-02-03-19.4. Drilling pits. A pit may be utilized to bury drill cuttings and

solids generated during well drilling and completion operations, providing the pit

can be constructed, used, and reclaimed in a manner that will prevent pollution

of the land surface and freshwaters. In special circumstances, the director may

prohibit construction of a cuttings pit or may impose more stringent pit construction

and reclamation requirements. Reserve and circulation of mud system through

earthen pits are prohibited unless a waiver is granted by the director. All pits shall

be inspected by an authorized representative of the director prior to lining and use.

Under no circumstances shall pits be used for disposal, dumping, or storage of

uids, wastes, and debris other than drill cuttings and solids recovered while drilling

and completing the well.

Drill cuttings and solids must be stabilized in a manner approved by the

director prior to placement in a cuttings pit. Any liquid accumulating in the cuttings

pit shall be promptly removed. The pit shall be diked in a manner to prevent surface

water from running into the pit.

A small lined pit can be authorized by the director for temporary containment

of incidental uids such as trench water and rig wash, if emptied and covered prior

to the rig leaving the site.

Pits shall not be located in, or hazardously near, bodies of water, nor shall

they block natural drainages. No pit shall be wholly or partially constructed in ll

dirt unless approved by the director.

When required by the director, the drilling pit or appropriate parts thereof

shall be fenced.

Within thirty days after the drilling of a well or expiration of a drilling permit,

drilling pits shall be reclaimed. The director may grant an extension of the thirty-day

time period to no more than one year for good reason. Prior to reclaiming the pit, the

operator or the operator’s agent shall le a sundry notice (form 4) with the director

and obtain approval of a pit reclamation plan. Verbal approval to reclaim the pit

may be given. The notice shall include:

1. The name and address of the reclamation contractor;

2. The name and address of the surface owner;

3. The location and name of the disposal site for the pit water when

applicable; and

4. A description of the proposed work, including details on treatment and

disposition of the drilling waste.

Any water or oil accumulated on the pit must be removed prior to

reclamation. Drilling waste shall be encapsulated in the pit and covered with

4/2012 30
at least four feet [1.22 meters] of backll and topsoil and surface sloped, when

practicable, to promote surface drainage away from the reclaimed pit area.

History: Effective April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-19.5. Reserve pit for drilling mud and drill cuttings from

shallow wells. For wells drilled to a strata or formation, including lignite or coal

strata or seam, located above the depth of ve thousand feet [1524 meters] below

the surface, or located more than ve thousand feet [1524 meters] below the

surface but above the top of the Rierdon formation, a container or reserve pit

of sufcient size to contain said material or uid, and the accumulation of drill

cuttings may be utilized to contain solids and uids used and generated during

well drilling and completion operations, providing the pit can be constructed,

used and reclaimed in a manner that will prevent pollution of the land surface

and freshwaters. A reserve pit may be allowed by an order of the commission

after notice and hearing for wells drilled within a specied eld and pool more

than ve thousand feet [1524 meters] below the surface and below the top of

the Rierdon formation provided the proposed well or wells utilized a low sodium

content water-based mud system, and the reserve pit can be constructed, used,

and reclaimed in a manner that will prevent pollution of the land surface and

freshwaters. In special circumstances, based on site-specic conditions, the

director or authorized representative may prohibit construction of a reserve pit

or may impose more stringent pit construction and reclamation requirements,

including reserve pits previously authorized by a commission order within a

specied eld and pool. Under no circumstances shall reserve pits be used for

disposal, dumping, or storage of uids, wastes, and debris other than drill cuttings

and uids used or recovered while drilling and completing the well.

Reserve pits shall not be located in, or hazardously near, bodies of water,

nor shall they block natural drainages. No reserve pit shall be wholly or partially

constructed in ll dirt unless approved by the director.

Within a reasonable time, but not more than one year after the completion

of a shallow well, or prior to drilling below the surface casing shoe on any other

well, the reserve pit shall be reclaimed. Prior to reclaiming the pit, the operator or

the operator’s agent shall le a sundry notice (form 4) with the director and obtain

approval of a pit reclamation plan. Verbal approval to reclaim the pit may be given.

The notice shall include:

1. The name and address of the reclamation contractor;

2. The name and address of the surface owner;

3. The location and name of the disposal site for the pit water; and

4. A description of the proposed work, including details on treatment and

disposition of the drilling waste.

31 4/2012
All pit water must be removed prior to reclamation. Drilling waste should be

encapsulated in the pit and covered with at least four feet [1.22 meters] of backll

and topsoil and surface sloped, when practicable, to promote surface drainage

away from the reclaimed pit area.

History: Effective April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-20. Sealing off strata. During the drilling of any oil or natural

gas well, all oil, gas, and water strata above the producing horizon shall be sealed

or separated where necessary in order to prevent their contents from passing into

other strata.

All freshwaters and waters of present or probable value for domestic,

commercial, or stock purposes shall be conned to their respective strata and

shall be adequately protected by methods approved by the commission. Special

precautions shall be taken in drilling and plugging wells to guard against any

loss of artesian water from the strata in which it occurs and the contamination of

artesian water by objectionable water, oil, or gas.

All water shall be shut off and excluded from the various oil-bearing and

gas-bearing strata which are penetrated. Water shutoffs shall ordinarily be made

by cementing casing or landing casing with or without the use of mud-laden uid.

History: Amended effective May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-21. Casing, tubing, and cementing requirements. All wells

drilled for oil, natural gas, or injection shall be completed with strings of casing which

shall be properly cemented at sufcient depths to adequately protect and isolate all

formations containing water, oil, or gas or any combination of these; protect the pipe

through salt sections encountered; and isolate the uppermost sand of the Dakota

group.

Drilling of the surface hole shall be with freshwater-based drilling mud or

other method approved by the director which will protect all freshwater-bearing

strata. The surface casing shall consist of new or reconditioned pipe that has been

previously tested to one thousand pounds per square inch [6900 kilopascals].

The surface casing shall be set and cemented at a point not less than fty feet

[15.24 meters] below the base of the Fox Hills formation. Sufcient cement shall

be used on surface casing to ll the annular space behind the casing to the bottom

of the cellar, if any, or to the surface of the ground. If the annulus space is not

adequately lled with cement, the director shall be notied immediately. The

operator shall diligently perform remedial work after obtaining approval from the

director. All strings of surface casing shall stand cemented under pressure for

at least twelve hours before drilling the plug or initiating tests. The term "under

pressure" as used herein shall be complied with if one oat valve is used or if

4/2012 32
pressure is otherwise held. Cementing shall be by the pump and plug method

or other methods approved by the director. The director is authorized to require

an accurate gauge be maintained on the surface casing of any well, not properly

plugged and abandoned, to detect any buildup of pressure caused by the migration

of uids.

Surface casing strings must be allowed to stand under pressure until the tail

cement has reached a compressive strength of at least ve hundred pounds per

square inch [3450 kilopascals]. All ller cements utilized must reach a compressive

strength of at least two hundred fty pounds per square inch [1725 kilopascals]

within twenty-four hours and at least three hundred fty pounds per square inch

[2415 kilopascals] within seventy-two hours. All compressive strengths on surface

casing cement shall be calculated at a temperature of eighty degrees Fahrenheit

[26.67 degrees Celsius].

Production or intermediate casing strings shall consist of new or

reconditioned pipe that has been previously tested to two thousand pounds

per square inch [13800 kilopascals]. Such strings must be allowed to stand

under pressure until the tail cement has reached a compressive strength of at

least ve hundred pounds per square inch [3450 kilopascals]. All ller cements

utilized must reach a compressive strength of at least two hundred fty pounds per

square inch [1725 kilopascals] within twenty-four hours and at least ve hundred

pounds per square inch [3450 kilopascals] within seventy-two hours, although

in any horizontal well performing a single stage cement job from a measured

depth of greater than thirteen thousand feet [3962.4 meters], the ller cement

utilized must reach a compressive strength of at least two hundred fty pounds per

square inch [1725 kilopascals] within forty-eight hours and at least ve hundred

pounds per square inch [3450 kilopascals] within ninety-six hours. All compressive

strengths on production or intermediate casing cement shall be calculated at

a temperature found in the Mowry formation using a gradient of 1.2 degrees

Fahrenheit per one hundred feet [30.48 meters] of depth plus eighty degrees

Fahrenheit [26.67 degrees Celsius].

After cementing, the casing string shall be tested by application of

pump pressure of at least one thousand ve hundred pounds per square inch

[10350 kilopascals]. If, at the end of thirty minutes, this pressure has dropped

one hundred fty pounds per square inch [1035 kilopascals] or more, the casing

shall be repaired after receiving approval from the director. Thereafter, the casing

shall again be tested in the same manner. Further work shall not proceed until a

satisfactory test has been obtained. The casing in a horizontal well may be tested

by use of a mechanical tool set near the casing shoe after the horizontal section

has been drilled.

All owing wells must be equipped with tubing. A tubing packer must also

be utilized unless a waiver is obtained after demonstrating the casing will not be

33 4/2012
subjected to excessive pressure or corrosion. The packer must be set as near the

producing interval as practicable, but in all cases must be above the perforations.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1,

1996; January 1, 1997; September 1, 2000; July 1, 2002; May 1, 2004; January 1,

2006; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-22. Defective casing or cementing. In any well that appears

to have defective casing or cementing, the operator shall report the defect to the

director on a sundry notice (form 4). Prior to attempting remedial work on any

casing, the operator must obtain approval from the director and proceed with

diligence to conduct tests, as approved or required by the director, to properly

evaluate the condition of the well bore and correct the defect. The director is

authorized to require a pressure test to verify casing integrity if its competence is

questionable. The director may allow the well bore condition to remain if correlative

rights can be protected without endangering potable waters. The well shall be

properly plugged if requested by the director.

Any well with open perforations above a packer shall be considered to have

defective casing.

History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000;

July 1, 2002; May 1, 2004; January 1, 2008.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-23. Blowout prevention. In all drilling operations, proper and

necessary precautions shall be taken for keeping the well under control, including

the use of a blowout preventer and high pressure ttings attached to properly

cemented casing strings adequate to withstand anticipated pressures. During the

course of drilling, the pipe rams shall be functionally operated at least once every

twenty-four-hour period. The blind rams shall be functionally operated each trip out

of the well bore. The blowout preventer shall be pressure tested at installation on

the wellhead, after modication of any equipment, and every thirty days thereafter.

The director may postpone such pressure test if the necessity therefor can be

demonstrated to the director’s satisfaction. All tests shall be noted in the driller’s

record.

History: Amended effective January 1, 1983; September 1, 2000; July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-24. Pulling string of casing. In pulling strings of casing from any

oil, gas, or injection well, the space above the casing stub shall be kept and left

full of uid with adequate gel strength and specic gravity, cement, or combination

thereof, to seal off all freshwater and saltwater strata and any strata bearing oil or

4/2012 34
gas not producing. No casing shall be removed without the prior approval of the

director.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-25. Deviation tests and directional surveys. When any well

is drilled or deepened, tests to determine the deviation from the vertical shall be

taken at least every one thousand feet [304.8 meters]. The director is authorized

to waive the deviation test for a shallow gas well if the necessity therefor can be

demonstrated to the director’s satisfaction. When the deviation from the vertical

exceeds ve degrees at any point, the director may require that the hole be

straightened. Directional surveys may be required by the director, whenever, in

the director’s judgment, the location of the bottom of the well is in doubt.

A directional survey shall be made and led with the director on any well

utilizing a whipstock or any method of deviating the well bore. The obligation to run

the directional survey may be waived by the director when a well bore is deviated

to sidetrack junk in the hole, straighten a crooked hole, control a blowout, or if the

necessity therefor can be demonstrated to the director’s satisfaction. The survey

contractor shall le with the director free of charge one certied electronic copy

of all surveys, in a form approved by the director, within thirty days of attaining

total depth. Such survey shall be in reference to true north. The director may

require the directional survey to be led immediately after completion if the survey

is needed to conduct the operation of the director’s ofce in a timely manner.

Special permits may be obtained to drill directionally in a predetermined direction

as provided above, from the director.

If the director denies a request for a permit to directionally drill, the director

shall advise the applicant immediately of the reasons for denial. The decision of

the director may be appealed to the commission.

History: Amended effective April 1, 1980; April 30, 1981; January 1, 1983; May 1,

1990; May 1, 1992; May 1, 1994; September 1, 2000; January 1, 2006; April 1,

2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-26. Multiple zone completions. Multiple zone completions in

any pool may be permitted by the director.

An application for a multiple zone completion shall be accompanied by an

exhibit showing the location of all wells on the applicant’s lease and all offset wells

on offset leases and shall set forth all material facts on the common sources of

supply involved and the manner and method of completion proposed.

Multiply completed wells shall at all times be operated, produced, and

maintained in a manner to ensure the complete segregation of the various

35 4/2012
common sources of supply. The director may require such tests as the director

deems necessary to determine the effectiveness of the segregation of the different

sources of supply.

History: Amended effective January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-27. Perforating, fracturing, and chemically treating wells.

The director may prescribe pretreatment casing pressure testing as well as other

operational requirements designed to protect wellhead and casing strings during

treatment operations. If damage results to the casing or the casing seat from

perforating, fracturing, or chemically treating a well, the operator shall immediately

notify the director and proceed with diligence to use the appropriate method and

means for rectifying such damage, pursuant to section 43-02-03-22. If perforating,

fracturing, or chemical treating results in irreparable damage which threatens the

mechanical integrity of the well, the commission may require the operator to plug

the well.

History: Amended effective January 1, 1983; May 1, 1992; April 1, 2010.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-27.1. Hydraulic fracture stimulation.

1. For hydraulic fracture stimulation performed through a frac string run

inside the intermediate casing string:

a. The frac string must be either stung into a liner or run with a packer

set at a minimum depth of one hundred feet [30.48 meters] below

the top of cement or one hundred feet [30.48 meters] below the top

of the Inyan Kara formation, whichever is deeper.

b. The intermediate casing-frac string annulus must be pressurized

and monitored during frac operations.

c. An adequately sized, function tested pressure relief valve must be

utilized on the treating lines from the pumps to the wellhead, with

suitable check valves to limit the volume of owback uid should the

relief valve open. The relief valve must be set to limit line pressure

to no more than eighty-ve percent of the internal yield pressure of

the frac string.

d. An adequately sized, function tested pressure relief valve and an

adequate sized diversion line must be utilized to divert ow from

the intermediate casing to a pit or containment vessel in case of

frac string failure. The relief valve must be set to limit annular

pressure to no more than eighty-ve percent of the lowest internal

yield pressure of the intermediate casing string.

4/2012 36
e. The surface casing valve must be fully open and connected to a

diversion line rigged to a pit or containment vessel.

f. An adequately sized, function tested remote operated frac valve

must be utilized between the treating line and the wellhead.

g. Within sixty days after the hydraulic fracture stimulation is

performed, the owner, operator, or service company shall post

on the fracfocus chemical disclosure registry all elements made

viewable by the fracfocus website.

2. For hydraulic fracture stimulation performed through an intermediate

casing string:

a. The maximum treating pressure shall be no greater than

eighty-ve percent of the American petroleum institute rating

of the intermediate casing.

b. Casing evaluation tools to verify adequate wall thickness of the

intermediate casing shall be run from the wellhead to a depth as

close as practicable to one hundred feet [30.48 meters] above the

completion formation and a visual inspection with photographs

shall be made of the top joint of the intermediate casing and the

wellhead ange.

If the casing evaluation tool or visual inspection indicates wall

thickness is below the American petroleum institute minimum or

a lighter weight of intermediate casing than the well design called

for, calculations must be made to determine the reduced pressure

rating. If the reduced pressure rating is less than the anticipated

treating pressure, a frac string shall be run inside the intermediate

casing.

c. Cement evaluation tools to verify adequate cementing of the

intermediate casing shall be run from the wellhead to a depth as

close as practicable to one hundred feet [30.48 meters] above the

completion formation.

(1) If the cement evaluation tool indicates defective casing or

cementing, a frac string shall be run inside the intermediate

casing.

(2) If the cement evaluation tool indicates the top of the cement

behind the intermediate casing is below the top of the Mowry

formation, a frac string shall be run inside the intermediate

casing.

d. The intermediate casing and wellhead must be pressure tested to

a minimum depth of one hundred feet [30.48 meters] below the top

37 4/2012
of the Tyler formation for at least thirty minutes with less than ve

percent loss to a pressure equal to or in excess of the maximum

frac design pressure.

e.

If the pressure rating of the wellhead does not exceed the maximum

frac design pressure, a wellhead and blowout preventer protection

system must be utilized during the frac.

f. An adequately sized, function tested pressure relief valve must

be utilized on the treating lines from the pumps to the wellhead,

with suitable check valves to limit the volume of owback uid

should be the relief valve open. The relief valve must be set

to limit line pressure to no greater than the test pressure of the

intermediate casing, less one hundred pounds per square inch

[689.48 kilopascals].

g. The surface casing value must be fully open and connected to a

diversion line rigged to a pit or containment vessel.

h. An adequately sized, function tested remote operated frac valve

must be utilized between the treating line and the wellhead.

i. Within sixty days after the hydraulic fracture stimulation is

performed, the owner, operator, or service company shall post

on the fracfocus chemical disclosure registry all elements made

viewable by the fracfocus website.

3. If during the stimulation, the pressure in the intermediate casing-surface

casing annulus exceeds three hundred fty pounds per square inch

[2413 kilopascals] gauge, the owner or operator shall verbally notify

the director as soon as practicable but no later than twenty-four hours

following the incident.

History: Effective April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-28. Safety regulation. During drilling operations all oil wells shall

be cleaned into a pit or tank, not less than forty feet [12.19 meters] from the derrick

oor and one hundred fty feet [45.72 meters] from any re hazard.

All owing oil wells must be produced through an approved oil and gas

separator or emulsion treater of ample capacity and in good working order. No

boiler, portable electric lighting generator, or treater shall be placed nearer than

one hundred fty feet [45.72 meters] to any producing well or oil tank. Placement

as close as one hundred twenty-ve feet [38.10 meters] may be allowed if a ame

arrestor is utilized on the equipment. Any rubbish or debris that might constitute

a re hazard shall be removed to a distance of at least one hundred fty feet

[45.72 meters] from the vicinity of wells and tanks. All waste shall be burned or

4/2012 38
disposed of in such manner as to avoid creating a re hazard. All vegetation must

be removed to a safe distance from any production equipment to eliminate a re

hazard.

The director may require remote operated or automatic shutdown equipment

to be installed on, or shut in for no more than forty days, any well that is likely to

cause a serious threat of pollution or injury to the public health or safety.

No well shall be drilled nor production or injection equipment installed less

than ve hundred feet [152.40 meters] from an occupied dwelling unless agreed to

in writing by the owner of the dwelling or authorized by order of the commission.

Subsurface pressure must be controlled during all drilling, completion,

and well-servicing operations with appropriate uid weight and pressure control

equipment.

History: Amended effective January 1, 1983; May 1, 1990; September 1, 2000;

January 1, 2006; January 1, 2008; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-29. Well and lease equipment. Wellhead and lease equipment

with a working pressure at least equivalent to the calculated or known pressure

to which the equipment may be subjected shall be installed and maintained.

Equipment on producing wells shall be installed to facilitate gas-oil ratio tests, and

static bottom hole or other pressure tests. Valves shall be installed and maintained

in good working order to permit pressure readings to be obtained on both casing

and tubing.

History: Amended effective January 1, 1983; January 1, 2006.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-30. Notication of res, leaks, spills, or blowouts. All

persons controlling or operating any well, pipeline, receiving tank, storage tank,

or production facility into which oil, gas, or water is produced, received, stored,

processed, or through which oil, gas, or water is injected, piped, or transported,

shall verbally notify the director within twenty-four hours after discovery of any re,

leak, spill, blowout, or release of uid. If any such incident occurs or travels offsite

of a facility, the persons, as named above, responsible for proper notication shall

within a reasonable time also notify the surface owners upon whose land the

incident occurred or traveled. Notication requirements prescribed by this section

shall not apply to any leak, spill, or release of uid that is less than one barrel total

volume and remains onsite of a facility. The verbal notication must be followed

by a written report within ten days after cleanup of the incident, unless deemed

unnecessary by the director. Such report must include the following information:

the operator and description of the facility, the legal description of the location of

the incident, date of occurrence, date of cleanup, amount and type of each uid

involved, amount of each uid recovered, steps taken to remedy the situation,

39 4/2012
cause of the accident, and action taken to prevent reoccurrence. The signature,

title, and telephone number of the company representative must be included on

such report. The persons, as named above, responsible for proper notication

shall within a reasonable time also provide a copy of the written report to the

surface owners upon whose land the incident occurred or traveled.

The commission, however, may impose more stringent spill reporting

requirements if warranted by proximity to sensitive areas, past spill performance,

or careless operating practices as determined by the director.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1,

1996; January 1, 2008; April 1, 2010.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-30.1. Leak and spill cleanup. At no time shall any spill or leak

be allowed to ow over, pool, or rest on the surface of the land or inltrate the soil.

Discharged uids must be properly removed and may not be allowed to remain

standing within or outside of diked areas, although the remediation of such uids

may be allowed onsite if approved by the director. Operators must respond with

appropriate resources to contain and clean up spills.

History: Effective April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-31. Well log, completion, and workover reports. After the

plugging of a well, a plugging record (form 7) shall be led with the director.

After the completion of a well, recompletion of a well in a different pool, or drilling

horizontally in an existing pool, a completion report (form 6) shall be led with the

director. In no case shall oil or gas be transported from the lease prior to the ling

of a completion report unless approved by the director. The operator shall cause

to be run an open hole electrical, radioactivity, or other similar log, or combination

of open hole logs, of the operator’s choice, from which formation tops and porosity

zones can be determined. The operator shall cause to be run a gamma ray log

from total depth to ground level elevation of the well bore. Prior to completing

the well, the operator shall cause to be run a log from which the presence and

quality of bonding of cement can be determined in every well in which production

or intermediate casing has been set. The obligation to log may be waived or

postponed by the director if the necessity therefor can be demonstrated to the

director’s satisfaction. Waiver will be contingent upon such terms and conditions

as the director deems appropriate. All logs run shall be available to the director at

the well site prior to proceeding with plugging or completion operations. All logs

run shall be submitted to the director free of charge. Logs shall be submitted as

one digital TIFF (tagged image le format) copy and one digital LAS (log ASCII)

formatted copy, or a format approved by the director. In addition, operators shall

le two copies of drill stem test reports and charts, formation water analyses,

core analyses, geologic reports, and noninterpretive lithologic logs or sample

descriptions if compiled by the operator.

4/2012 40
All information furnished to the director on new permits, except the operator

name, well name, location, spacing or drilling unit description, spud date, rig

contractor, central tank battery number, and any production runs, shall be kept

condential for not more than six months if requested by the operator in writing.

The six-month period shall commence on the date the well is completed or the

date the written request is received, whichever is earlier. If the written request

accompanies the application for permit to drill or is led after permitting but prior to

spudding, the six-month period shall commence on the date the well is spudded.

The director may release such condential completion and production data to

health care professionals, emergency responders, and state, federal, or tribal

environmental and public health regulators if the director deems it necessary to

protect the public’s health, safety, and welfare.

All information furnished to the director on recompletions or reentries, except

the operator name, well name, location, spacing or drilling unit description, spud

date, rig contractor, and any production runs, shall be kept condential for not more

than six months if requested by the operator in writing. The six-month period shall

commence on the date the well is completed or the date the well was approved

for recompletion or reentry, whichever is earlier. Any information furnished to the

director prior to approval of the recompletion or reentry shall remain public.

Approval must be obtained on a sundry notice (form 4) from the director prior

to perforating or recompleting a well in a pool other than the pool in which the well

is currently permitted.

After the completion of any remedial work, or attempted remedial work

such as plugging back or drilling deeper, acidizing, shooting, formation fracturing,

squeezing operations, setting liner, perforating, reperforating, or other similar

operations not specically covered herein, a report on the operation shall be led

on a sundry notice (form 4) with the director. The report shall present a detailed

account of all work done and the date of such work; the daily production of oil, gas,

and water both prior to and after the operation; the shots per foot, size, and depth

of perforations; the quantity of sand, crude, chemical, or other materials employed

in the operation; and any other pertinent information or operations which affect the

original status of the well and are not specically covered herein.

Upon the installation of pumping equipment on a owing well, or change in

type of pumping equipment designed to increase productivity in a well, the operator

shall submit a sundry notice (form 4) of such installation. The notice shall include

all pertinent information on the pump and the operation thereof including the date

of such installation, and the daily production of the well prior to and after the pump

has been installed.

All forms, reports, logs, and other information required by this section shall

be submitted within thirty days after the completion of such work, although a

41 4/2012
completion report shall be led immediately after the completion or recompletion

of a well in a pool or reservoir not then covered by an order of the commission.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1,

1992; May 1, 1994; July 1, 1996; September 1, 2000; July 1, 2002; January 1,

2006; January 1, 2008; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-32. Stratigraphic test and core holes. Stratigraphic test and

core holes shall be permitted the same as oil and gas wells, although no setback

from a drilling unit shall be required.

History: Amended effective April 30, 1981; January 1, 1983; July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-33. Notice of intention to plug well. The operator or the

operator’s agent shall le a notice of intention (form 4) to plug with the director,

and obtain the approval of the director, prior to the commencement of plugging or

plug-back operations. The notice shall state the name and location of the well, the

name of the operator, and the method of plugging, which must include a detailed

statement of proposed work. In the case of a recently completed test well that

has not had production casing in the hole, the operator may commence plugging

by giving reasonable notice to, and securing verbal approval of, the director as

to the method of plugging, and the time plugging operations are to begin. Within

thirty days after the plugging of any well has been accomplished, the owner or

operator thereof shall le a plugging record (form 7), and, if requested, a copy of

the cementer’s trip ticket or job receipt, with the director setting forth in detail the

method used in plugging the well.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

January 1, 2006.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-34. Method of plugging. All wells shall be plugged in a manner

which will conne permanently all oil, gas, and water in the separate strata

originally containing them. This operation shall be accomplished by the use of

mud-laden uid, cement, and plugs, used singly or in combination as may be

approved by the director. All casing strings shall be cut off at least three feet [91.44

centimeters] below the nal surface contour, and a cap shall be welded thereon.

Core or stratigraphic test holes drilled to or below sands containing freshwater

4/2012 42
shall be plugged in accordance with the applicable provisions recited above. After

plugging, the site must be reclaimed pursuant to section 43-02-03-19.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1,

1992; July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-34.1. Reclamation of surface.

1. Within a reasonable time, but not more than one year, after a well is

plugged, or if a permit expires, has been canceled or revoked, the well

site, access road, and other associated facilities constructed for the

well shall be reclaimed as closely as practicable to original condition.

Prior to site reclamation, the operator or the operator’s agent shall

le a sundry notice (form 4) with the director and obtain approval of

a reclamation plan. The operator or operator’s agent shall provide a

copy of the proposed reclamation plan to the surface owner at least

ten days prior to commencing the work unless waived by the surface

owner. Verbal approval to reclaim the site may be given. The notice

shall include:

a. The name and address of the reclamation contractor;

b. The name and address of the surface owner and the date when a

copy of the proposed reclamation plan was provided to the surface

owner;

c. A description of the proposed work, including topsoil redistribution

and reclamation plans for the access road and other associated

facilities; and

d. Reseeding plans, if applicable.

The commission will mail a copy of the approved notice to the surface

owner.

All equipment, waste, and debris shall be removed from the site. Flow

lines shall be purged in a manner approved by the director. Flow lines

shall be removed if buried less than three feet [91.44 centimeters] below

nal contour.

2. Gravel or other surfacing material shall be removed, stabilized soil

shall be remediated, and the well site, access road, and other

associated facilities constructed for the well shall be reshaped as near

as practicable to original contour.

3. The stockpiled topsoil shall be evenly distributed over the disturbed

area and, where applicable, the area revegetated with native species

43 4/2012
or according to the reasonable specications of the appropriate

government land manager or surface owner.

4. Within thirty days after completing any reclamation, the operator shall

le a sundry notice with the director reporting the work performed.

5. The director, with the consent of the appropriate government land

manager or surface owner, may waive the requirement of reclamation

of the site and access road after a well is plugged.

History: Effective April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-35. Conversion of mineral wells to freshwater wells. Any

person desiring to convert a mineral well to a freshwater well, as provided by North

Dakota Century Code section 61-01-27, shall le an application for approval with

the commission. The application must include, but is not limited to, the following:

1. If the well is to be used for other than individual domestic and livestock

use, a conditional water permit issued by the state water commission.

2. An afdavit by the person desiring to obtain approval for the conversion

stating that such person has the authority and assumes all liability for

the use and plugging of the proposed freshwater well.

3. The procedure which will be followed in converting the mineral well to a

freshwater well.

4. If the well is not currently plugged and abandoned, an afdavit must

be executed by the operator of the well indicating that the parties

responsible for plugging the mineral well have no objection to the

conversion of the mineral well to a freshwater well.

If the commission, after notice and hearing, determines that a mineral well may

safely be used as a freshwater well, the commission may approve the conversion.

History: Amended effective April 30, 1981; January 1, 1983; September 1, 1987;

July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-36. Liability. The owner and operator of any well, core hole, or

stratigraphic test hole, whether cased or uncased, shall be liable and responsible

4/2012 44
for the plugging and site reclamation thereof in accordance with the rules and

regulations of the commission.

History: Amended effective January 1, 1983; May 1, 1994.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-37. Slush pits. Repealed effective January 1, 1983.

43-02-03-38. Preservation of cores and samples. Repealed effective

January 1, 1983.

43-02-03-38.1. Preservation of cores and samples. Sample cuttings of

formations, taken at regular intervals in all wells drilled for oil or gas or geologic

information in North Dakota, shall be washed and packaged in standard sample

envelopes which in turn shall be placed in proper order in a standard sample box;

carefully identied as to operator, well name, location, depth of sample; and shall be

sent free of cost to the state geologist within thirty days after completion of drilling

operations.

The operator of any well drilled for oil or gas in North Dakota, during the

drilling of or immediately following the completion of any well, shall inform the state

geologist or the geologist’s representative of all intervals that are to be cored, or

have been cored. All cores taken shall be preserved and forwarded to the state

geologist, free of cost, within ninety days after completion of drilling operations,

unless specically exempted by the state geologist. If an exemption is granted, the

operator shall advise the state geologist of the nal disposition of the core.

This section does not prohibit the operator from taking such samples of the

core as the operator may desire for identication and testing. The operator shall

furnish the state geologist with the results of identication and testing procedures.

History: Effective October 1, 1990; amended effective January 1, 2006.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-39. Limiting gas-oil ratio. In the event the commission has not

set a limiting gas-oil ratio for a particular pool, the operator of any well in such pool

whose gas-oil ratio exceeds two thousand shall demonstrate to the director that

production from such well should not be restricted pending a hearing before the

commission to establish a limiting gas-oil ratio. The director may restrict production

of any well with a gas-oil ratio exceeding two thousand, until the commission can

determine that restrictions are necessary to conserve reservoir energy.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

January 1, 2006.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

45 4/2012
43-02-03-39.1. Oil production limitation. In the event the commission has

not established spacing and special eld rules for a particular oil pool, oil production

from any well completed therein shall be a maximum of two thousand barrels per

day until the commission issues a decision after hearing. The director shall have

the authority to waive production limitations for good cause, and for special tests.

History: Effective July 1, 1996.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-40. Gas-oil ratio test. Each operator shall take a gas-oil ratio test

within thirty days following the completion or recompletion of an oil well. Each test

shall be conducted using standard industry practices unless otherwise specied

by the director. The initial gas-oil ratio must be reported on the well completion

or recompletion report (form 6). After the discovery of a new pool, each operator

shall make additional gas-oil ratio tests as directed by the director or provided for

in eld rules. During tests each well shall be produced at a maximum efcient rate.

The director may shut in any well for failure to make such test until such time as

a satisfactory test can be made, or satisfactory explanation given. The results of

all gas-oil ratio tests shall be submitted to the director on form 9, which shall be

accompanied by a statement that the data on form 9 is true and correct.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-41. Subsurface pressure tests. The operator shall make

a subsurface pressure test on the discovery well of any new pool hereafter

discovered and shall report the results thereof to the director within thirty days after

the completion of such discovery well. Drill stem test pressures are acceptable.

After the discovery of a new pool, each operator shall make additional subsurface

pressure tests as directed by the director or provided for in eld rules. All tests

shall be made by a person qualied by both training and experience to make

such tests and with an approved subsurface pressure instrument. All wells shall

remain completely shut in for at least forty-eight hours prior to the test. The

subsurface determination shall be obtained as close as possible to the midpoint of

the productive interval of the reservoir. The report of the reservoir pressure test

shall be led on form 9a.

The director may shut in any well for failure to make such test as herein

above described until such time as a satisfactory test has been made or satisfactory

explanation given.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

4/2012 46
43-02-03-42. Commingling of oil from pools. Except as directed by

the commission after hearing, each pool shall be produced as a single common

reservoir without commingling in the well bore of uids from different pools. After

uids from different pools have been brought to surface, such uids may be

commingled provided that the amount of production from each pool is determined

by a method approved by the director.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-43. Control of multiply completed wells. Repealed effective

January 1, 1983.

43-02-03-44. Metered casinghead gas. All casinghead gas produced

shall be reported monthly to the director in units of one thousand cubic feet [28.32

cubic meters] computed at a pressure of fourteen and seventy-three hundredths

pounds per square inch absolute [1034.19 grams per square centimeter] at a base

temperature of sixty degrees Fahrenheit [15.56 degrees Celsius]. Associated gas

production may not be transported from a well premises or central production

facility until its volume has been determined through the use of properly calibrated

measurement equipment. All measurement equipment and volume determinations

must conform to American gas association standards. The operator of a well shall

notify the director of the connection date to a gas gathering system, the metering

equipment, transporter, and purchaser of the gas. Any gas produced and used

on lease for fuel purposes or ared must be estimated and reported on a gas

production report (form 5b) in accordance with section 43-02-03-52.1.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1,

1996; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-45. Vented casinghead gas. Pending arrangements for

disposition for some useful purpose, all vented casinghead gas shall be burned.

Each are shall be equipped with an automatic ignitor or a continuous burning

pilot, unless waived by the director for good reason. The estimated volume of

gas used and ared shall be reported to the director on a gas production report

(form 5b) on or before the fth day of the second month succeeding that in which

gas is produced.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1,

1992; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-46. Use of vacuum pumps. Repealed effective January 1, 1983.

47 4/2012
43-02-03-47. Produced water. Monthly water production from each well

must be determined through the use of properly calibrated meter measurements,

tank measurements, or an alternate measurement method approved by the

director. This includes allocating water production back to individual wells on

a monthly basis, provided the method of volume determination and allocation

procedure results in reasonably accurate production volumes. Operators shall

report monthly to the director the amount of water produced by each well on

form 5. The reports must be led on or before the rst day of the second month

following that in which production occurred.

History: Amended effective January 1, 1983; May 1, 1992; May 1, 1994;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-48. Measurement of oil. Oil production may not be transported

from a well premises or central production facility until its volume has been

determined through the use of properly calibrated meter measurements or tank

measurements. All meter and tank measurements, and volume determinations

must conform to American petroleum institute standards and be corrected to a

base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius].

History: Amended effective April 30, 1981; March 1, 1982; January 1, 1983; May 1,

1992; May 1, 1994; July 1, 1996.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-48.1. Central production facility - Commingling of production.

1. The director shall have the authority to approve requests to consolidate

production equipment at a central location.

2. Commingling of production from two or more wells in a central

production facility is prohibited unless approved by the director. There

are two types of central production facilities in which production from

two or more wells is commingled that may be approved by the director.

a. A central production facility in which all production going into the

facility has common ownership (working interests, royalty interests,

and overriding royalties).

b. A central production facility in which production going into the

facility has diverse ownership.

3. The commingling of production in a central production facility from two or

more wells having common ownership may be approved by the director

provided the production from each well can be accurately determined

at reasonable intervals. Commingling of production in a central

production facility from two or more wells having diverse ownership

4/2012 48
may be approved by the director provided the production from each

well is accurately metered prior to commingling. Commingling of

production in a central production facility from two or more wells having

diverse ownership that is not metered prior to commingling may only

be approved by the commission after notice and hearing.

a. Common ownership central production facility. The application for

permission to commingle oil and gas in a central production facility

with common ownership must be submitted on a sundry notice

(form 4) and shall include the following:

(1) A plat or map showing thereon the location of the central

facility and the name, well le number, and location of each

well and ow lines from each well that will produce into the

facility.

(2) A schematic drawing of the facility which diagrams the

testing, treating, routing, and transferring of production. All

pertinent items such as treaters, tanks, ow lines, valves,

meters, recycle pumps, etc., should be shown.

(3) An afdavit executed by a person who has knowledge as to

the state of title indicating ownership is common.

(4) An explanation of the procedures or method to be used to

determine, accurately, individual well production at periodic

intervals. Such procedures or method shall be performed at

least once every three months.

A copy of all tests are to be led with the director on form 11

within thirty days after the tests are completed.

b. Diverse ownership central production facility. The application for

permission to commingle oil and gas in a central production facility

having diverse ownership must be submitted on a sundry notice

(form 4) and shall include the following:

(1) A plat or map showing thereon the location of the central

facility and the name, well le number, and location of each

well, and ow lines from each well that will produce into the

facility.

(2) A schematic drawing of the facility which diagrams the

testing, treating, routing, and transferring of production. All

pertinent items such as treaters, tanks, ow lines, valves,

meters, recycle pumps, etc., should be shown.

(3) The name of the manufacturer, size, and type of meters to be

used. The meters must be proved at least once every three

49 4/2012
months and the results reported to the director within thirty

days following the completion of the test.

(4) An explanation of the procedures or method to be used to

determine, accurately, individual well production at periodic

intervals. Such procedures or method shall be performed

monthly.

A copy of all tests are to be led with the director on form 11

within thirty days after the tests are completed.

4. Any changes to a previously approved central production facility must

be reported on a sundry notice (form 4) and approved by the director.

History: Effective May 1, 1992; amended effective September 1, 2000; May 1,

2004.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-49. Oil production equipment, dikes, and seals. Storage of

oil in underground or partially buried tanks or containers is prohibited. Surface oil

tanks and production equipment must be devoid of leaks and in good condition.

Unused tanks and production equipment must be removed from the site or placed

into service, within a reasonable time period, not to exceed one year. Dikes must

be erected and maintained around oil tanks at any production facility built or rebuilt

on or after July 1, 2000.

Dikes must be erected around oil tanks at any new production facility

within thirty days after the well has been completed. Dikes must be erected and

maintained around oil tanks at production facilities built prior to July 1, 2000, when

deemed necessary by the director. Dikes as well as the base material under the

dikes and within the diked area must be constructed of sufciently impermeable

material to provide emergency containment. Dikes must be of sufcient dimension

to contain the total capacity of the largest tank plus one day’s uid production.

The required capacity of the dike may be lowered by the director if the necessity

therefor can be demonstrated to the director’s satisfaction.

Numbered metal security seals shall be properly utilized on all oil access

valves and access points to secure the tank or battery of tanks.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000; July 1, 2002; May 1, 2004; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-50. Tank cleaning permit. No tank bottom waste shall be

removed from any tank used for the storage or sale of crude oil without prior

approval by the director. Verbal approval may be given. Prior approval to remove

4/2012 50
tank bottom waste from tanks not used for the storage or sale of crude oil is not

required.

Within thirty days of the removal of the tank bottom waste of any tank used

for the storage or sale of crude oil, the owner or operator shall submit a report

(form 23) showing an accurate gauge of the contents of the tank and the amount

of merchantable oil determinable from a representative sample of the tank bottom

by the standard centrifugal test as prescribed by the American petroleum institute’s

code for measuring, sampling, and testing crude oil.

Within thirty days of the removal of the tank bottom waste of any permanent

tank not used for the storage or sale of crude oil, the owner or operator shall submit

a sundry notice (form 4) detailing the cleaning operation.

All tank bottom waste must be disposed of in a manner authorized by the

director and in accordance with all applicable local, state, and federal laws and

regulations. Nothing contained in this section shall apply to reclaiming of pipeline

break oil or the treating of tank bottoms at a pipeline station, crude oil storage

terminal, or renery or to the treating by a gasoline plant operator of oil and other

catchings collected in traps and drips in the gas gathering lines connected to

gasoline plants and in scrubbers at such plants.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1,

1994; September 1, 2000; May 1, 2004.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-51. Treating plant. Before construction of a treating plant and

upon written application for a treating plant permit stating in detail the location,

type, capacity of the plant contemplated, method of processing proposed, and the

plan of operation for all plant waste, the commission shall set such application for

hearing to determine whether the proposed plant and method of processing will

actually and efciently process, treat, and reclaim tank bottom emulsion and other

waste oils, and whether there is need for such a plant. The operator of any portable

treating plant shall notify the director as to all changes in location of said plant. No

treating plant shall operate except by order of the commission. The disposition

of all products and waste must be reported monthly on form 5p. Upon approval

of a treating plant and before construction begins, the permittee shall le with the

commission a surety bond or cash bond conditioned upon compliance with all laws,

rules and regulations, and orders of the commission. The bond amount shall be

specied in the commission order authorizing the treating plant and shall be based

upon the location, type, and capacity of the plant, processing method, and plan of

operation for all plant waste approved in the commission order and shall be payable

51 4/2012
to the industrial commission of North Dakota. In no case shall the bond amount be

set lower than fty thousand dollars.

History: Amended effective January 1, 1983; May 1, 1990; May 1, 1992;

September 1, 2000; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-52. Report of oil production. The operator of each well in every

pool shall, on or before the rst day of the second month succeeding the month

in which production occurs, le with the director the amount of production made

by each such well upon form 5 or approved computer sheets no larger than eight

and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be

signed by both the person responsible for the report and the person witnessing the

signature. The printed name and title of both the person signing the report and

the person witnessing the signature shall be included. Wells for which reports of

production are not received by the close of business on said rst day of the month

may be shut in for a period not to exceed thirty days. The director shall notify, by

certied mail, the operator and authorized transporter of the shut-in period for such

wells. Any oil produced during such shut-in period shall be deemed illegal oil and

subject to the provisions of North Dakota Century Code section 38-08-15.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

December 1, 1997; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-52.1. Report of gas produced in association with oil. The

operator of each well in every pool shall, on or before the fth day of the second

month succeeding the month in which production occurs, le with the director the

amount of gas produced by each such well upon form 5b or approved computer

sheets no larger than eight and one-half by eleven inches [21.59 by 27.94

centimeters]. The report shall be signed by both the person responsible for the

report and the person witnessing the signature. The printed name and title of both

the person signing the report and the person witnessing the signature shall be

included. Wells for which reports of production are not received by the close of

business on said fth day of the month may be shut in for a period not to exceed

thirty days. The director shall notify, by certied mail, the operator and authorized

transporter of the shut-in period for such wells. Any gas produced during such

shut-in period must be deemed illegal gas and subject to the provisions of North

Dakota Century Code section 38-08-15.

History: Effective May 1, 1992; amended effective December 1, 1997;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-53. Saltwater handling facilities.

4/2012 52
1. All saltwater liquids or brines produced with oil and natural gas shall

be processed, stored, and disposed of without pollution of freshwater

supplies.

2. Underground injection of saltwater liquids and brines shall be in

accordance with chapter 43-02-05.

3. Surface facilities are acceptable provided that:

a. They are devoid of leaks and constructed of materials resistant to

the effects of produced saltwater liquids, brines, or chemicals that

may be contained therein. The above materials requirement may

be waived by the director for tanks presently in service and in good

condition. Unused tanks and injection equipment must be removed

from the site or placed into service, within a reasonable time period,

not to exceed one year.

b. Dikes must be erected and maintained around saltwater tanks at

any saltwater handling facility built or rebuilt on or after July 1,

2000. Dikes must be erected around saltwater tanks at any

new facility within thirty days after the well has been completed.

Dikes must be erected and maintained around saltwater tanks

at saltwater handling facilities built prior to July 1, 2000, when

deemed necessary by the director. Dikes as well as the base

material under the dikes and within the diked area must be

constructed of sufciently impermeable material to provide

emergency containment. Dikes must be of sufcient dimension to

contain the total capacity of the largest tank plus one day’s uid

production. The required capacity of the dike may be lowered by

the director if the necessity therefor can be demonstrated to the

director’s satisfaction. Discharged saltwater liquids or brines must

be properly removed and may not be allowed to remain standing

within or outside of any diked areas.

4. The operator shall take steps to minimize the amount of solids stored

at the facility.

5. Any salable crude oil recovered from a saltwater handling facility shall

be reported on a form 5 SWD.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000; July 1, 2002; May 1, 2004; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-54. Investigative powers. Upon receipt of a written complaint

from any surface owner or lessee, royalty owner, mineral owner, local, state, or

federal ofcial, alleging a violation of the oil and gas conservation statutes or any

rule, regulation, or order of the commission, the director shall within a reasonable

53 4/2012
time reply in writing to the person who submitted the complaint stating that an

investigation of such complaint will be made or the reason such investigation will

not be made. The person who submitted the complaint may appeal the decision of

the director to the commission. The director may also conduct such investigations

on the director’s own initiative or at the direction of the commission. If, after such

investigation, the director afrms that cause for complaint exists, the director shall

report the results of the investigation to the person who submitted the complaint, if

any, to the person who was the subject of the complaint and to the commission. The

commission shall institute such legal proceedings as, in its discretion, it believes

are necessary to enjoin further violations.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; April 1,

2012.

General Authority: NDCC 38-08-04, 38-08-12

Law Implemented: NDCC 38-08-04, 38-08-12

43-02-03-55. Abandonment of wells - Suspension of drilling.

1. The removal of production equipment or the failure to produce oil or

gas, or the removal of production equipment or the failure to produce

water from a source well, for one year constitutes abandonment of

the well. The removal of injection equipment or the failure to use an

injection well for one year constitutes abandonment of the well. The

failure to plug a stratigraphic test hole within one year of reaching

total depth constitutes abandonment of the well. An abandoned well

must be plugged and its site must be reclaimed pursuant to sections

43-02-03-34 and 43-02-03-34.1.

2. The director may waive for one year the requirement to plug and reclaim

an abandoned well by giving the well temporarily abandoned status.

This status may only be given to wells that are to be used for purposes

related to the production of oil and gas. If a well is given temporarily

abandoned status, the well’s perforations must be isolated, the integrity

of its casing must be proven, and its casing must be sealed at the

surface, all in a manner approved by the director. The director may

extend a well’s temporarily abandoned status beyond one year. A fee

of one hundred dollars shall be submitted for each application to extend

the temporary abandonment status of any well.

3. In addition to the waiver in subsection 2, the director may also waive the

duty to plug and reclaim an abandoned well for any other good cause

found by the director. If the director exercises this discretion, the director

shall set a date or circumstance upon which the waiver expires.

4. The director may approve suspension of the drilling of a well. If

suspension is approved, a plug must be placed at the top of the

casing to prevent any foreign matter from getting into the well. When

drilling has been suspended for thirty days, the well, unless otherwise

4/2012 54
authorized by the director, must be plugged and its site reclaimed

pursuant to sections 43-02-03-34 and 43-02-03-34.1.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1,

1992; August 1, 1999; January 1, 2008; April 1, 2010; April 1, 2012.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-56. Underground disposal of water. Repealed effective

November 1, 1982.

43-02-03-57. Determination of gas well potential. After the completion or

recompletion of a gas well, the operator shall conduct tests to determine the daily

open ow potential of the well. The test results together with an analyses of the

gas shall be reported to the director within thirty days after completion of the well.

Operators shall conduct either a stabilized one-point back-pressure test or

a multipoint back-pressure test in accordance with the "Manual of Back-Pressure

Testing of Gas Wells" published by the interstate oil and gas compact commission

unless otherwise approved by the director.

History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-58. Method and time of shut-in pressure tests. Repealed

effective January 1, 1983.

43-02-03-59. Production from gas wells to be measured and reported.

Gas production may not be transported from gas well premises until its volume

has been determined through the use of properly calibrated measurement

equipment. All measurement equipment and volume determinations must conform

to American gas association standards and corrected to a pressure of fourteen

and seventy-three hundredths pounds per square inch absolute [1034.19 grams

per square centimeter] at a base temperature of sixty degrees Fahrenheit [15.56

degrees Celsius]. Gas production reports (form 5b) shall be led with the director

on or before the fth day of the second month succeeding that in which production

occurs.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1,

1994; July 1, 1996; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-60. Natural gas utilization. Repealed effective January 1, 1983.

55 4/2012
43-02-03-60.1. Valuation of ared gas. The value of gas ared from an

oil well in violation of North Dakota Century Code section 38-08-06.4 shall be

determined by the commission after notice and hearing.

History: Effective October 1, 1990; amended effective May 1, 1992; May 1, 1994;

May 1, 2004.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-06.4

43-02-03-60.2. Flaring exemption. The connection of a well to a natural

gas gathering line is "economically infeasible" under North Dakota Century Code

section 38-08-06.4, if the direct costs of connecting the well to the line and the

direct costs of operating the facilities connecting the well to the line during the life

of the well, are greater than the amount of money the operator is likely to receive

for the gas, less production taxes and royalties, should the well be connected. In

making this calculation, the applicant may add ten percent to the amount of the cost

of connecting the well and of operating the connection facilities used to determine

whether a connection is economically infeasible. This ten percent may be added

in consideration of the cost of money and other overhead costs that are not gured

in the direct costs of connecting the well and operating the connecting facilities.

An applicant for an exemption under North Dakota Century Code section

38-08-06.4 must, at the minimum, present evidence covering the following areas:

1. Basis for the gas price used to determine whether it is economically

infeasible to connect the well to a natural gas gathering line;

2. Cost of connecting the well to the line and operating the facilities

connecting the well to the line;

3. Current daily rate of the amount of gas ared; and

4. The amount of gas reserves and the amount of gas available for sale.

History: Effective May 1, 1994.

General Authority: NDCC 38-07-04

Law Implemented: NDCC 38-08-06.4

43-02-03-61. Storage gas. With the exception of the requirement to meter

and report monthly the amount of gas injected and the amount of gas withdrawn

from storage, in the absence of waste, this chapter shall not apply to gas being

injected into or removed from storage.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-62. Carbon dioxide, coal bed methane, helium, and nitrogen.

Insofar as is applicable, the provisions of this chapter relating to gas, gas wells,

4/2012 56
and gas reservoirs shall also apply to carbon dioxide, coal bed methane, helium,

nitrogen, carbon dioxide wells, coal bed methane wells, helium wells, nitrogen

wells, carbon dioxide reservoirs, coal bed methane reservoirs, helium reservoirs,

and nitrogen reservoirs.

History: Amended effective January 1, 1983; September 1, 1987; July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-63. Regulation of pools. To prevent waste and to protect

correlative rights, when the commission nds that total production in an area

signicantly exceeds the reasonable market demand and undue marketing

discrimination is occurring, the commission may prorate or distribute the allowable

production among proration units upon a reasonable basis through rules,

regulations, or orders pertaining to any pool or area after notice and hearing.

History: Amended effective January 1, 1983; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-64. Rate of producing wells. In allocated oil and gas pools the

owner or operator of any proration unit shall not produce from the unit during any

proration period more oil or gas than the allowable production from such unit as

shown by the proration schedule, provided that such owners or operators shall be

permitted to maintain a uniform rate of production for each unit during the proration

period. In order to maintain a uniform rate of production from the pool during any

proration period, any operator may produce a total volume of oil and gas equal to

that shown on the applicable proration schedule plus ve days unit allowable, and

any such overproduction may be deducted from the total allowable for the well in

the second month following.

Where the commission has established spacing rules in any pool, proration

units shall consist of spacing units.

History: Amended effective January 1, 1983; September 1, 2000; January 1, 2008;

April 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-65. Authorization for production, purchase, and

transportation. When necessary the commission shall hold a hearing to set

proration unit allowables for the state.

The commission shall consider all evidence of market demand for oil and

gas, including sworn statements of individual demand as submitted by each

purchaser or buyer in the state, and determine the amount to be produced from

all pools. The amount so determined will be allocated among the various pools

in accordance with existing regulations and in each pool in accordance with

regulations governing each pool. In allocated pools, effective the rst day of

57 4/2012
each proration period, the commission will issue a proration schedule which will

authorize the production of oil and gas from the various units in strict accordance

with the schedule, and the purchase and transportation of such production.

Allowable for wells completed after the rst day of the proration period will become

effective from the date of well completion. A supplementary order will be issued

by the commission to the operator of a newly completed or recompleted well,

and to the purchaser or transporter of the production from a newly completed

or recompleted well, establishing the effective date of completion, the amount

of production permitted during the remainder of the proration period, and the

authority to purchase and transport same from said proration unit.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1,

1996; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-66. Application for allowable on new oil wells. No well shall be

placed on the proration schedule until a completion report (form 6) has been led

with the director.

The discovery well of any pool hereafter discovered shall be allowed to

produce at a maximum efcient rate until such time as proper spacing is set for

the pool, and shall produce thereafter, only pursuant to the general proration rules

and regulations of the commission.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-67. Oil proration. At the beginning of each calendar month, the

distribution or proration to the respective proration units shall be changed in order

to take into account all new wells which have been completed and were not in

the proration schedule during the previous calendar month. Where any well is

completed between the rst and last day of the calendar month, its proration unit

shall be assigned an allowable beginning at seven a.m., on the date of completion

and for the remainder of that calendar month.

History: Amended effective January 1, 1983; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-68. Gas-oilratio limitation. In allocated pools containing a well or

wells producing from a reservoir which contains both oil and gas, each proration unit

shall be permitted to produce only that volume of gas equivalent to the applicable

limiting gas-oil ratio multiplied by the proration unit oil allowable currently assigned

to the pool. In the event the commission has not set a gas-oil ratio limit for a

particular oil pool, the limiting gas-oil ratio shall be two thousand cubic feet [56.63

cubic meters] of gas for each barrel of oil produced.

4/2012 58
A gas-oil limit shall be placed on all allocated oil pools, and all proration

units having a gas-oil ratio exceeding the limit for the pool shall be adjusted unless

previously exempted by the commission after hearing, in accordance with the

following formula:

1. Any proration unit which, on the basis of the latest ofcial gas-oil ratio

test has a gas-oil ratio in excess of the limiting gas-oil ratio for the

pool in which it is located, shall be permitted to produce that number

of barrels of oil which shall be determined by multiplying the proration

unit allowable by the fraction, the numerator of which shall be the limiting

gas-oil ratio for the pool and the denominator of which shall be the ofcial

gas-oil ratio test of the well.

2. Any unit containing a well or wells producing from a reservoir which

contains both oil and gas shall be permitted to produce only that volume

of gas equivalent to the applicable limiting gas-oil ratio multiplied by the

proration unit allowable currently assigned to the pool.

All proration units to which gas-oil ratio adjustments are applied shall be so

indicated in the proration schedule with adjusted allowables stated. The adjustment

shall be made effective on the rst day of the month following that in which the

gas-oil ratio tests were reported for the pool, as set forth in the special eld rules

applicable to the pool.

In cases of new pools the limiting gas-oil ratio shall be two thousand cubic

feet [56.63 cubic meters] per barrel until such time as changed by the commission

after a hearing. After notice and hearing, the commission shall determine or

redetermine, the specic gas-oil ratio limit which is applicable to a particular

allocated oil pool.

History: Amended effective January 1, 1983; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-69. Allocation of gas production. When the commission

determines that allocation of gas production in a designated gas pool is necessary

to prevent waste, and to protect correlative rights, the commission, after notice and

hearing, shall consider the nominations of purchasers from that gas pool and other

relevant data, and shall x the allowable production of that pool, and shall allocate

production among the proration units in the pool delivering to a gas transportation

facility upon a reasonable basis.

The commission shall include in the proration schedule of such pool any

proration unit which it nds is being unreasonably discriminated against through

59 4/2012
denial of access to a gas transportation facility which is reasonably capable of

handling the type of gas producible from such proration unit.

History: Amended effective January 1, 1983; January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-70. Gas proration period. The gas proration period shall be set

by order of the commission.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-71. Adjustment of gas allowables. When the actual market

demand from any allocated gas pool during a proration period is more than or

less than the allowable set by the commission for the pool for the period, the

commission shall adjust the gas proration unit allowables for the pool for the next

proration period so that each gas proration unit shall have a reasonable opportunity

to produce its fair share of the gas production from the pool in a manner that shall

protect correlative rights.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-72. Gas proration units. Before issuing a proration schedule for

an allocated gas pool, the commission, after notice and hearing, shall x the gas

proration unit for that pool.

General Authority: NDCC 38-08-04, 38-08-06

Law Implemented: NDCC 38-08-04, 38-08-06

43-02-03-73. Permit for injection of gas, air, or water. Repealed effective

November 1, 1982.

43-02-03-74. Casing and cementing of injection wells. Repealed

effective November 1, 1982.

43-02-03-75. Notice of commencement and discontinuance of injection

operations. Repealed effective November 1, 1982.

43-02-03-76. Records. Repealed effective November 1, 1982.

43-02-03-77. Application for unitized management under commission

order. Any plan of unitized management or any injection into a reservoir for the

purpose of maintaining reservoir pressure or for enhanced recovery operations

shall be permitted only by order of the commission after notice and hearing. The

4/2012 60
application for an order shall include a complete statement of all matters required

by North Dakota Century Code section 38-08-09 et seq.

The application shall be submitted to the commission, in duplicate, at

least forty-ve days prior to the date requested for such hearings and shall be

accompanied by all engineering, geological, and other technical exhibits which will

be introduced at the hearing.

In addition, the application shall set forth that all the provisions of North

Dakota Century Code section 38-08-09.5 have been complied with.

History: Amended effective November 1, 1982; January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-09

Law Implemented: NDCC 38-08-09

43-02-03-78. Illegal sale prohibited. Repealed effective January 1, 1983.

43-02-03-79. Purchase of liquids from gas wells. Provided that a

supplemental order is issued authorizing such production on the proration

schedule, any common purchaser is authorized to purchase one hundred percent

of the amount of associated crude oil or condensate produced and recovered from

a gas proration unit.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-06

Law Implemented: NDCC 38-08-06

43-02-03-80. Reports of purchasers and transporters of crude oil. On

or before the rst day of the second month succeeding that in which oil is removed,

purchasers and transporters, including truckers, shall le with the director the

appropriate monthly reporting forms. The purchaser shall le on form 10 and the

transporter on form 10a the amount of all crude oil removed and purchased by

them from each well or central production facility during the reported month. The

transporter shall report the disposition of such crude oil on form 10b. All meter

and tank measurements, and volume determinations of crude oil removed and

purchased from a well or central production facility must conform to American

petroleum institute standards and corrected to a base temperature of sixty degrees

Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three hundredths

pounds per square inch absolute [1034.19 grams per square centimeter].

Prior to removing any oil from a well or central production facility, purchasers

and transporters shall obtain an approved copy of a producer’s authorization to

purchase and transport oil from a well or central production facility (form 8) from

either the producer or the director.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1,

1992; May 1, 1994; July 1, 1996; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

61 4/2012
43-02-03-81. Authorization to transport oil from a well or central

production facility. Before any crude oil is transported from a well or central

production facility, the operator of the well or central production facility shall le

with the director, and obtain the director’s approval, an authorization to purchase

and transport oil from a well or central production facility (form 8).

Oil transported from a well or central production facility before the

authorization is obtained or if such authorization has been revoked shall be

considered illegal oil.

The director may revoke the authorization to purchase and transport oil from

a well or central production facility for failure to comply with any rule, regulation, or

order of the commission.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1,

1996; September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-81.1. Reports of purchases for resale and transporting of dry

gas. Transporters of and purchasers for the resale of dry gas shall le a report

(form 8a) with the director showing the amount of gas taken from each plant or well

during the monthly reporting period.

All gas shall be reported monthly to the director in one thousand cubic

feet [28.32 cubic meters] computed at a pressure of fourteen and seventy-three

hundredths pounds per square inch [1034.19 grams per square centimeter]

absolute at a base temperature of sixty degrees Fahrenheit [15.56 degrees

Celsius].

History: Effective January 1, 1983; amended effective May 1, 1992; July 1, 1996.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-82. Renery reports. Each rener of oil within North Dakota shall

furnish for each calendar month a report (form 13) containing information and data

respecting crude oil and products involved in such rener’s operations during each

month. The report for each month shall be prepared and led on or before the

fteenth of the next succeeding month with the director.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992;

September 1, 2000.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-83. Gas processing plant reports. Each operator of a gas

processing plant, cycling plant, or any other plant at which gas processing,

gasoline, butane, propane, condensate, kerosene, oil, or other products are

4/2012 62
extracted from gas shall furnish to the director a report containing the amount of

gas received from each lease or well on form 12a.

Crude oil recovered shall be reported to the director, on form 5 on or before

the close of business on the rst day of the second month succeeding that in which

oil is removed. Other operations shall be reported to the director, on form 12 and

12a, on or before the fth day of the second month following that in which gas is

processed.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-84. Additional information may be required. This chapter shall

not be taken or construed to limit or restrict the authority of the commission to

require the furnishing of such additional reports, data, or other information relative

to production, transportation, storing, rening, processing, or handling of crude oil,

gas, or products as may appear to be necessary or desirable, either generally or

specically, for the prevention of waste, protection of correlative rights, and the

conservation of natural resources.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-85. Books and records to be kept to substantiate reports. All

producers, transporters, storers, reners, gasoline or extraction plant operators,

and initial purchasers within North Dakota shall make and keep appropriate books

and records for a period not less than six years, covering their operations in North

Dakota from which they may be able to make and substantiate the reports required

by this chapter.

History: Amended effective January 1, 1983; July 1, 2002.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-86. Public hearing required. Repealed effective January 1,

1983.

43-02-03-87. Institute proceedings. Repealed effective January 1, 1983.

43-02-03-88. Application for hearing. In any proceeding instituted upon

application, the application shall be signed by the applicant or by the applicant’s

attorney. An application shall state (1) the name and general description of the

common source or sources of supply affected by the order, rule, or regulation

sought if any, unless same is intended to apply to and affect the entire state, in

which event the application shall so state, and such statement shall constitute

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sufcient description; and (2) briey the general nature of the order, rule, or

regulation sought in the proceedings.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-11

Law Implemented: NDCC 38-08-11

43-02-03-88.1. Special procedures for increased density wells,

pooling, aring exemption, underground injection, commingling, converting

mineral wells to freshwater wells, and central tank battery or central

production facilities applications.

1. Applications to amend eld rules to allow additional wells on existing

spacing units, for pooling under North Dakota Century Code section

38-08-08, for a aring exemption under North Dakota Century Code

section 38-08-06.4 and section 43-02-03-60.2, for underground

injection under chapter 43-02-05, for commingling in one well bore the

uids from two or more pools under section 43-02-03-42, for converting

a mineral well to a freshwater well under section 43-02-03-35, and

for establishing central tank batteries or central production facilities

under section 43-02-03-48.1, must be signed by the applicant or the

applicant’s representative. The application must contain or refer to

attachments that contain all the information required by law as well

as the information the applicant wants the commission to consider

in deciding whether to grant the application. The application must

designate an employee or representative of the applicant to whom the

commission can direct inquiries regarding the application.

2. The applications referred to in subsection 1 will be advertised and

scheduled for hearing as are all other applications received by the

commission. The applicant, however, unless required by the director,

need not appear at the hearing scheduled to consider the application,

although additional evidence may be submitted prior to the hearing.

Any interested party may appear at the hearing to oppose or comment

on the application. Any interested party may also submit written

comments on or objections to the application no later than ve p.m. on

the last business day prior to the hearing date. Such submissions may

be part of the record in the case if allowed by the hearing examiner.

3. The director is authorized, on behalf of the commission, to grant or deny

the applications referred to in subsection 1.

4. In any proceeding under this section, the applicant, at the hearing, may

supplement the record by offering testimony and exhibits in support of

the application.

5. In the event the applicant is not required by the director to appear at the

hearing and an interested party does appear to oppose the application

or submits a written objection to the application, the hearing ofcer

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shall continue the hearing to a later date, keep the record open for the

submission of additional evidence, or take any other action necessary

to ensure that the applicant, who does not appear at the hearing as the

result of subsection 2, is accorded due process.

History: Effective May 1, 1992; amended effective May 1, 1994; May 1, 2004;

April 1, 2012.

General Authority: NDCC 38-08-04, 38-08-11

Law Implemented: NDCC 38-08-04, 38-08-08

43-02-03-88.2. Hearing participants by telephone. In any hearing, the

commission may, at its option, allow telephonic communication of witnesses and

interested parties. The procedure shall be as follows:

1. Telephonic communication of an applicant’s witness will only be

considered if a written request is made at least two business days prior

to the hearing date.

2. Telephonic communication of an interested party will only be considered

if said party noties the applicant and the commission in writing at least

three business days prior to the hearing date. Such notice shall include

the subject hearing, the name and telephone number of the interested

party, and the name and telephone number of the interested party’s

attorney or representative that will be present at the hearing.

3. In the event an objection to any party’s telephonic communication is

received, the examiner may disallow such communication by telephone

and may reschedule for an in-person hearing. The commission will

notify all parties whether or not the request to participate by telephone

is granted or denied.

4. All parties participating by telephone shall have an attorney or

representative present at the hearing who shall be responsible

for actually calling said party once the case is called for hearing,

for providing the commission at the time of the hearing with any

documentary evidence requested to be included in the record, and for

any other matters necessary for the party to participate by telephone.

5. All parties participating by telephone shall le an afdavit verifying the

identity of such party. The record of such telephonic communication

shall not be considered evidence in the case unless said afdavit

is received by the examiner prior to an order being issued by the

commission. The commission shall provide a form afdavit. The

commission has the discretion to refuse to consider all or any part of

the information received from any party participating by telephone.

6. For all hearings allowing communication by telephone, the commission

shall provide a hearing room equipped with a speaker telephone.

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7. The cost of telephonic communication shall be paid by the party

requesting its use.

History: Effective July 1, 2002; amended effective May 1, 2004.

General Authority: NDCC 38-08-11

Law Implemented: NDCC 28-32-11

43-02-03-89. Upon application hearing is set. Repealed effective

January 1, 1983.

43-02-03-90. Hearings - Complaint proceedings - Emergency

proceedings - Other proceedings.

1. Except as more specically provided in North Dakota Century Code

section 38-08-11, the rules of procedure established in subsection 1

of North Dakota Century Code section 28-32-21 apply to proceedings

involving a complaint and a specic-named respondent.

2. For proceedings that do not involve a complaint and a specic-named

respondent the commission shall give at least fteen days’ notice

(except in emergency) of the time and place of hearing thereon by

one publication of such notice in a newspaper of general circulation in

Bismarck, North Dakota, and in a newspaper of general circulation in

the county where the land affected or some part thereof is situated,

unless in some particular proceeding a longer period of time or a

different method of publication is required by law, in which event such

period of time and method of publication shall prevail. The notice shall

issue in the name of the commission and shall conform to the other

requirements provided by law.

3. In case an emergency is found to exist by the commission which in its

judgment requires the making of a rule or order without rst having a

hearing, the emergency rule or order shall have the same validity as

if a hearing with respect to the same had been held after notice. The

emergency rule or order permitted by this section shall remain in force

no longer than forty days from its effective date, and in any event, it shall

expire when the rule or order made after due notice and hearing with

respect to the subject matter of such emergency rule or order becomes

effective.

Any person moving for a continuance of a hearing, and who is granted a

continuance, shall submit a twenty-ve dollar fee to the commission to pay the

cost of republication of notice of the hearing.

History: Amended effective March 1, 1982; January 1, 1983; May 1, 1990; May 1,

1992; May 1, 1994; July 1, 1996; July 1, 2002.

General Authority: NDCC 38-08-11

Law Implemented: NDCC 28-32-05, 38-08-11

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43-02-03-90.1. Investigatory hearings. The commission may hold

investigatory hearings upon the institution of a proceeding by application or by

motion of the commission. Notice of the hearing must be served upon all parties

personally or by certied mail at least ve days before the hearing.

History: Effective May 1, 1992.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-90.2. Ofcial record. The evidence in each case heard by

the commission, unless specically excluded by the hearing ofcer, includes the

certied directional surveys, and all oil, water, and gas production records on le

with the commission.

Any interested party may submit written comments on or objections to the

application prior to the hearing date. Such submissions must be received no later

than ve p.m. on the last business day prior to the hearing date and may be part

of the record in the case if allowed by the hearing examiner.

History: Effective May 1, 1992; amended effective April 1, 2010; April 1, 2012.

General Authority: NDCC 28-32-06

Law Implemented: NDCC 28-32-06

43-02-03-90.3. Petitions for review of recommended order and oral

arguments prohibited. Neither petitions for review of a recommended order nor

oral arguments following issuance of a recommended order and pending issuance

of a nal order are allowed.

History: Effective May 1, 1992.

General Authority: NDCC 28-32-13

Law Implemented: NDCC 28-32-13

43-02-03-90.4. Notice of order by mail. The commission may give notice

of an order by mailing the order, and ndings and conclusions upon which it is

based, to all parties by regular mail provided it les an afdavit of service by mail

indicating upon whom the order was served.

History: Effective May 1, 1992.

General Authority: NDCC 28-32-13

Law Implemented: NDCC 28-32-13

43-02-03-90.5. Service and ling. All pleadings, notices, written

motions, requests, petitions, briefs, and correspondence to the commission or

commission employee from a party (or vice versa) relating to a proceeding after its

commencement, must be led with the director and entered into the commission’s

ofcial record of the procedure provided the record is open at the time of receipt.

All parties shall receive copies upon request of any or all of the evidence in the

record of the proceedings. The commission may charge for the actual cost of

67 4/2012
providing copies of evidence in the record. Unless otherwise provided by law, ling

shall be complete when the material is entered into the record of the proceeding.

History: Effective May 1, 1992.

General Authority: NDCC 28-32-13

Law Implemented: NDCC 28-32-13

43-02-03-91. Rehearing. Repealed effective May 1, 1992.

43-02-03-92. Burden of proof. Repealed effective January 1, 1983.

43-02-03-93. Designation of examiners. The commission may by

motion designate and appoint qualied individuals to serve as examiners. The

commission may refer any matter or proceeding to any legally designated and

appointed examiner or examiners.

History: Amended effective April 30, 1981; January 1, 1983.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-94. Matters to be heard by examiner. Repealed effective

January 1, 1983.

43-02-03-95. Powers and duties of examiner. The commission may by

motion limit the powers and duties of any examiner in any particular case to such

issues or to the performance of such acts as the commission deems expedient;

however, subject only to such limitation as may be ordered by the commission, the

examiner or examiners to whom any matter or proceeding is referred under this

chapter shall have full authority to hold hearings on such matter or proceeding in

accordance with and pursuant to this chapter. The examiner shall have the power

to regulate all proceedings before the examiner and to perform all acts and take all

measures necessary or proper for the efcient and orderly conduct of such hearing,

including ruling on prehearing motions, the swearing of witnesses, receiving of

testimony and exhibits offered in evidence, subject to such objections as may be

imposed, and shall cause a complete record of the proceeding to be made and

retained.

History: Amended effective January 1, 1983; May 1, 1990.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-96. Matters heard by commission. Repealed effective

January 1, 1983.

43-02-03-97. Examiner disinterested umpire. Repealed effective

January 1, 1983.

43-02-03-98. Report of examiner. Upon the conclusion of any hearing

before an examiner, the examiner shall promptly consider the proceedings in such

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hearing, and based upon the record of such hearing, the examiner shall prepare a

report and recommendations for the disposition of the matter or proceeding by the

commission. Such report and recommendations shall either be accompanied by a

proposed order or shall be in the form of a proposed order, and shall be submitted

to the commission.

History: Amended effective January 1, 1983.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-99. Commission order from examiner hearing. After receipt of

the report and recommendations of the examiner, the commission shall enter its

order disposing of the matter or proceeding.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

43-02-03-100. Hearing de novo before commission. Repealed effective

January 1, 1983.

43-02-03-101. Prehearing motion practice. In a matter pending before

the commission, all prehearing motions must be served by the moving party upon

all parties affected by the motion. Service must be upon a party unless a party

is represented by an attorney, in which case service must be upon the attorney.

Service must be made by delivering a copy of the motion and all supporting papers

in conformance with one of the means of service provided for in rule 5(b) of the

North Dakota Rules of Civil Procedure. Proof of service must be made as provided

in rule 4 of the North Dakota Rules of Civil Procedure or by the certicate of an

attorney showing that service has been made. Proof of service must accompany

the ling of a motion. Any motion led without proof of service is not properly before

the commission.

History: Effective May 1, 1990; amended effective January 1, 2006.

General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04

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